The oil and gas industry of today requires a social license to operate. As positive public perception diminishes, the industry must adapt to a higher standard of operation to reduce its environmental footprint and are able to fit on any rig, anywhere in the world.

On average, drilling fluid losses total on average more than 5,000 gallons per well. In Canada, industry adaptation is 98% in directing the discharge of fluid during connections. Yet only 12% of Canadian drilling rigs have systems in place to capture and recycle directed fluid. Mud costs and remediation expenses can be reduced by capturing and recycling fluid before it hits the ground.

There is a misperception that environmental stewardship involves a prohibitive price tag. This article will illustrate the adverse effects of noncontainment, introduce proactive technology and demonstrate benefits of zero spill systems.

SOCIAL LICENSE

Oil companies need the support or acquiescence of the population in areas where they produce oil. Where the “social license to operate” is not forthcoming, the company becomes impaired. In North America, the perception that the oil and gas industry does not provide the proper stewardship to responsibly produce hydrocarbons in a sustainable manner results in many sensitive areas being set aside or severely restricted from oil and gas production. The protection of the fragile ecologies of arctic permafrost, semi-arid deserts, wetlands, and coastal marshes are the targeted issue in these areas.

To secure access and ensure that invested assets see a return, leading companies recognize the need for improving and maintaining positive public perception of the industry while minimizing the effects of E&P operations.

Drilling operations have come a long way in improving the safety of the crew and protection of the environment. Operating companies today recognize the benefits of providing a safer work environment and minimizing their environmental impact. However, in many cases, safety and environmental performance can hit a ceiling without a fundamental change in the “fit, form or function” of the traditional rotary drilling operation.

Unfortunately, many companies still believe that being proactive with fluid capture is cost-prohibitive. But systems are available today that make it easy to minimize drilling’s environmental footprint while improving rig safety and providing a positive ROI.

THE PROBLEM

Before 1994, the industry was faced with three major problems without readily available solutions:

1. Poor public perception resulting in restriction of E&P activity.
2. Substantial environmental contamination and water loss resulting from uncontrolled discharge of drilling fluid into the environment.
3. Economic losses caused by expensive drilling fluids, environmental reclamation costs, and time lost in inefficient production practices.

Efforts were made to manage the uncontrolled discharge of drilling fluids on rigs, with some headway made. Yet the problems remained.

Today, oil and gas developments around the world continue to experience opposition from local communities, as well as local, national, and international non-governmental organizations. Companies are also attracting the wrong kind of attention from the media and investors. In some cases, companies have been forced to sever exploration and abandon significant investments of time and resources.

In the Alberta province, oil sands deposits have been described by Time Magazine as “Canada’s greatest buried energy treasure” and “could satisfy the world’s demand for petroleum for the next century”.” In 2006, Alberta’s oil sands were the source of about 62% of the province’s total crude oil and equivalent production and about 47% of all crude oil and equivalent produced in Canada (www.energy.gov.ab.ca).

But there remain challenges to public perception with the development of these deposits, as illustrated by an article published in the Calgary Herald in April 2008, titled “Alberta fights ‘dirty oil’ stigma.”

It has also been revealed that the province will spend $25 million over three years on an advertising and marketing campaign to boost the Alberta “brand.” That is $25 million taken from taxpayers because of negative public perception.

Companies have learned it is critical to their success that they earn a social license to operate – the unwritten social contract among companies, society and communities for industry to operate in tune with community needs and expectations. In fact, industry itself has little patience for members that are not pulling their weight. A generation has grown up since the environmental movement began. Some of these young people, steeped in environmental sensitivity, work for oil companies, regulators or environmental watchdog organizations.

The triple bottom line is becoming entrenched in business thinking: measuring corporate performance in terms of environmental sustainability and social responsibility, as well as profits.

CONTAMINATION

In order to ensure environmental sustainability for future generations, we need to remain conscious at all times of how we develop our resources in relation to the impact on the land and the environment. A continuing effort is also needed by regulators to encourage improvements in the management of exploration and production wastes. Historically, management of large quantities of produced water, as well as drilling fluids and associated wastes, was perceived as unavoidable in the oilfield.

Prior to the early 1980s, there were relatively few practical incentives to focus on reducing or eliminating wastes in oilfield processes and practices. For example, in the United States, the Resource Conservation and Recovery Act established in 1976, which controls the disposal of all solid waste, hazardous and non-hazardous, classifies produced water, drilling fluids and associated wastes as statutorily non-hazardous; this made them – the largest volume of waste in the oilfield – fully exempt from hazardous waste control (Holliday, George H. 1995).

Environmental protection efforts in Canada and the US have generally concentrated on methods for treatment and disposal of wastes after the wastes had been generated.

Each time a rig makes or breaks a connection while drilling, an average of 5 to 15 gallons of drilling fluid spills out onto the rotary table, down onto the substructure and into the ground. Drilling fluid losses total on average more than 5,000 gallons per well. Considering that 1 gallon of invert (oil-based drilling fluid) contaminates 1 cu m of soil, this is a serious issue.

Across North America, many resource plays require horizontal techniques to maximize productivity, along with drilling fluid regimes that minimize pressure differentials. This combination of factors amplifies the releases of drilling fluids, whether going in or out of the hole.

Some companies have reported average surface losses of over 8,000 gallons of drilling fluid on a typical Woodford, Fayetteville or Barnett horizontal well. On problematic wells, these amounts can balloon to more than 42,000 gallons.

Many operators consider this a cost of doing business. Lost drilling fluid costs can approach tens of thousands of dollars per well and can run into hundreds of thousands. In addition to fluid costs, this lost fluid is generally directed onto the ground, where it may sit for the remainder of the drilling time of the well.

Responsible operators pay to continually clean the site, and even go to great lengths to position vacuum trucks on location to clean up excess fluids spilled and to contain the fluid for later disposal. The well site often can get inundated with the fluid as it becomes difficult to clean up because of its viscosity or oily nature.

MEASURING INTANGIBLES

In the past decade, changes in industry perspectives have made the reactive approach to waste management much less attractive. With the public’s heightened awareness of environmental impact and protection, plus industry’s need to reduce costs and environmental liability and to comply with broadened regulations, there is a greater incentive to improve waste management processes and practices.

But how does one measure the value of an avoided cost? This is a common question when dealing with measuring the economic benefits of implementing proactive HSE and waste minimization solutions.  Generally speaking, there are three areas to evaluate.

The first approach is to identify the factors contributing to personnel injury claims and evaluate the associated expenses. Factors contributing to these accidents include:

• Uncontrolled drilling fluid discharge on the drill floor, resulting in slippery surfaces and footing.
• Uncontrolled drilling fluid discharge on the drill floor, resulting in risk for hypothermia during winter drilling.
• Worker health effects from skin contact and inhalation of airborne chemicals from drilling fluid exposure.

Direct costs are:

• Lost production from shut-downs and stop-work orders.
• Workers compensation assessments.
• Equipment repair and replacement.
• Fines and legal fees.
• Increases in insurance premiums.

Indirect costs are:

• Lower productivity and higher staff turnover due to low morale.
• Lost business due to tarnished image and failure to fill orders.
• Hiring and training time for replacement workers.
• Salaries of recovering and replacement workers.

The next area to review is drilling fluid costs. How much drilling fluid are you using during E&P activities? How much could you save by recovering and recycling your drilling fluid?

Each well has over 100 variables that can influence the price of the drilling fluid system utilized. However, there are three major types of drilling fluids: water-based, oil-based and synthetic-based.

Ground reclamation

The degree of contamination or impact that drilling fluids have on the environment depends on the type of mud used and the prevailing environmental conditions.

This directly correlates to reclamation costs. Generally speaking, offshore operations use water-based drilling fluids to avoid negative environmental impact.

In contrast, discharges of water-based drilling fluids during onshore operations can raise environmental problems with regard to its salt content and the chemicals used to change the mud’s density and viscosity properties.

Oil companies can spend between $60,000 and $80,000 or more to reclaim a land drilling site back to a functional status. In addition, there is liability associated with generated wastes within the oil and gas industry. The Alberta Environmental Protection & Enhancement Act (EPEA) requires that operators conserve and reclaim lands disturbed by their activities.

Convoy of trucks

There’s currently a 25-year liability for surface reclamation issues and a lifetime liability for contamination. This alone could have astounding long-term economic impacts.

The guidelines established by the Canadian Council of Ministers of the Environment are used for determining the degree of contamination allowed before remediation is required on sites throughout Canada.

The measurement standards used are milligrams of contaminant / kilogram of soil. This equals 1 milligram for every 1,000 grams of soil or 1 milligram for 1 million milligrams of soil. The numbers for allowable contamination vary from 130 mg/kg to 6600 mg/kg depending on the type of soil usage, structure, nearness to water and type of contaminant.

We often use the expression of 1 ounce of prevention being worth a pound of cure. Since 130 mg/kg equals 1 oz/481 lbs of soil, we should change the expression to: “An ounce of prevention is worth 481 pounds of cure.”

SOLUTION

A new standard in environmental protection and health and safety has become a reality through the zero spill technology (Figure 1). This equipment system directly supports the protection and preservation of the land and water in which the industry operates, by reducing drilling fluid releases and increasing operational safety.

Figure 1: Zero spill technology integrated components are: 1) new-style mud bucket, 2) safety, traction and containment mat, 3) drilling fluid splash guard, 4) new-style tray composed of polymers, 5) junk basket, 6) window stripper, 7) lower collection tray, 8 ) reducer collar, and 9) adjustable containment enclosure.

Each component addresses a specific problem encountered from cradle to grave, i.e., solutions for the exploratory drilling rig to the service rig to the abandoned wellhead. This article will review solutions for drilling rig operations.

The system’s components work together to address the 4 R’s: Reduce, Reuse, Recover and Recycle. They all interconnect and operate together and will provide optimal results as a system. When fully installed and used correctly, full containment of drilling fluids can be achieved.

Old steel mud bucket

New-style mud bucket composed of super polymers

The main purpose of a mud bucket is to control and redirect drilling fluids during drill floor procedures, like tripping, to keep the fluid in the circulation system. This helps to keep the fluids off of the drill floor, reducing slip hazards, and off of personnel, reducing potentially hazardous exposure.

Evolved solution: The traditional steel mud bucket designed in 1939 fits onto drill pipe and weighs around 260 lbs.  The fluids caught within the bucket are carried back into the rig system through a large hose.

New style mud bucket

The new-style mud bucket, composed of super polymers, weighs 27 lbs; installation requires only one person. It controls and redirects fluids down through the slips/rotary table instead of through a large hose. This eliminates dangerous trip hazards on the drill floor.

Quick-exchange seals (2 in. to 8 in.) allow the bucket to fit most drillstrings in its entirety, i.e. the Kelly, drill pipe, heavy weight, drill collars, test tools, core barrels, service tubing, or casing. These seals remain supple in extreme temperatures and fit tightly around the tool joint. Its locking handles are also designed to eliminate crush injuries during operations.

Safety & containment mat

Safety, traction and containment mat

The constant activity on a rig floor can make for a hazardous environment. Matting systems have existed for over 20 years and have become more comprehensive with each new product.

Figure 2: The safety, traction and containment mat is anti-slip and anti-fatigue. To enhance safety, it can also be color-coordinated for different zones, i.e., safe zone is green, danger zone is red and caution zone is yellow.

Evolved solution: This fully adaptable Lego-style mat (Figure 2) is the only safety mat that also provides containment. It was designed to reduce rig floor accidents, including lost-time incidents and fatalities due to slips and tong-handling procedures. It also channels fluid to the containment system. The key benefits of this temperature- and invert-resistant matting are:

• Fluid containment: Channels between the buttons coupled with the yellow/safe border redirect fluids to a containment system beneath the work floor.
• Anti-slip: provides traction with protruding “buttons” without the use of dangerous steel studs.
• Anti-fatigue: absorbs shock and is durable, therapeutic and ergonomic.
• Safety: can be color-coordinated for different zones (i.e., safe zones = green, danger zones = red, caution zones = yellow, etc).
• Adaptable: The Lego-style design allows it to be expanded and configured to accommodate any shape.

Drilling fluid splash guard/slip handle guard

Splash guard

Although drilling fluid is being redirected through the rotary table by the super polymer-based mud bucket, the performance is highly dependent on the height it is being used at on the drillstring. If it is being used too high up the string, some splashing may occur at the foot level.

Ineffective homemade device

Evolved solution: A conical super polymer-based splash guard (Figure 1) is used to aid the mud bucket in redirecting any low fluid splashes into the slips/rotary table. Other benefits are:

• Installs quickly without tools, easily connecting to the mat.
• Keeps hoses and other foreign objects out of Kelly/master bushings while drilling.
• Prevents injuries by keeping floorhands’ feet off of master bushings and out of slip handles.
• Durable but flexible: will bend over when stepped on but pops back up after pressure is taken off. Personnel can lift the slips at the same height as usual when pulling or inserting slips.

New-style tray composed of super polymers

Steel pans

It was established that an object was needed to catch the drilling fluid before it has the opportunity to dirty the stack and substructure, as well as result in environmental contamination. Collection trays were introduced just below the rig floor in an effort to collect these fluids.

Super polymer tray

Evolved solution: The first attempt was the use of steel pans, which were found to be cumbersome and dangerous. The installation and removal process of the steel pans resulted in an increased injury and fatality rate. Installation also required a time-consuming welding process.

In 1994, a new-style tray composed of super polymers was introduced (Figures 1 and 3). Its composition made its weight approximately 10% of previous steel trays. Installation occurs quickly and without tools directly below the work floor with the help of over-center latches. The drilling fluids are collected and recirculated into the system as they are redirected into the annulus. A 5-in. telescopic action was also incorporated to allow the tray to be installed tightly beneath the floor without problems during rig settling.

Junk basket

Junk basket

Incidents of tools or objects falling down the annulus are common on drilling rigs. These objects must then be fished out. Fishing trips require drilling to stop and may even require the drillstring to be pulled out of the hole.

Figure 3: The new-style tray composed of polymers (5), junk basket (6), and window stripper (7). The composition makes it weigh just 10% of previous steel trays.

Evolved solution: The junk basket is an integral component of the super polymer-based collection tray. After the flow nipple is modified with the junk basket, the collection tray is clamped onto the blue seal on the junk basket so that it is directly under the rotary table (Figure 3).

The junk basket also allows for the 5-in.telescopic action. In conjunction with the window stripper, the horizontal slots of the basket allow fluids, not foreign objects, back into the flow nipple for recirculation. Those items that do fall down the annulus are now caught within the catch tray, thus eliminating costly fishing trips.

Window stripper

Window stripper

As mentioned, fishing trips are costly and time-consuming. Keeping the stack and substructure clean is also an issue.

Evolved solution: Placed on top of the junk basket, the window stripper strips fluid off the drill pipe and redirects it into the flow nipple and the collection tray.

Other benefits include:

• A radial split enables installation onto the drillstring without needing to break the string apart.
• Openings through the window stripper allow flow checks to occur without needing to pull the master bushing.
• Composed of self-lubricating composite.
• Allows bi-directional fluid movement.
• Reduces the chance of master bushings being blown out of rotary table under kick conditions.

Lower collection tray

Lower collection tray

After introducing the first two components of the zero spill technology, it was determined that approximately 80-85% of the fluids were being contained. What can we do to catch the remaining 15-20%?

Evolved solution: Working in conjunction with all components above it, the lower collection tray “catches” any additional fluids that come though the drill floor. This is especially important under kick conditions. The tray can be retrofitted to fit anywhere on the stack (Figure 4). Its tongue and groove design with over-center latches allows for easy installation without tools.

With four hangers attached to the BOPs, it can be used as a work platform, making it ideal for underbalanced work and servicing rotating heads. It has four 4-in. drain boxes and hoses that return the captured fluid to the holding tank or mud tanks.

Reducer collar

With any efficient spill containment or waste minimization system, a major problem is finding a system that can outfit the multi-diversification of sub and stack configurations. Normally, each rig needs to undergo costly modifications in order to ensure the effectiveness of the containment system.

Evolved solution: The reducer collar seals the lower collection tray to all BOP applications (Figure 4). Along with its multi-fitting options, the collar allows fitting to all rotating head applications.

Figure 4: There are several installation options for the lower collection tray using the reducer collar. It seals the lower collection tray to all BOP applications.

Adjustable containment enclosure

Containment enclosure

Weather can impact the fluid containment role of zero spill technology, especially under windy conditions that can be found on offshore rigs.

Evolved solution: The adjustable containment enclosure catches any fluids escaping the other components of the system.  Features include:

• Fits any application. It is adjustable from 1 ft to 10 ft in height and from 10 ft to 16 ft in diameter.
• Composed of cross-stitched anti-rip material.
• Designed with access doors and H₂S warning signs.
• Designed for windy conditions.

OVERALL BENEFITS

Placing a measurable value on a preventive mechanism is a tricky endeavor. Every drilling and service rig is unique and operates under different conditions. However, by stopping pollution from occurring at the source, zero spill technology takes a number of variables out of the equation. Keeping this in mind, the benefits are telling but intangible: You can’t measure waste when you don’t lose anything.

When zero spill technology is properly utilized in its entirety, the result is a successfully implemented waste minimization plan that also optimizes the health, safety and operational performance of oil and gas operations. These best practices will raise the performance level of oil companies and contractors, as well as employee and public perceptions of the company and the industry at large.

Two independent third-party assessment reports have helped to record the tangible impacts of the technology. The first assessment was conducted over a period of five months by a national oil company. The benefits measured included only three of the numerous possible areas for cost savings: time gained in installation, time gained in dismantling, and the direct cost savings in the recovery of drilling fluids.

Total cost savings were estimated to be over $500,000, which comes to an almost 700% return on investment. The intangible benefits would boost ROI further. The following is an excerpt from their results summary:

The above-mentioned technology test was conducted on the Puerto Ceiba well 135, rig 339 of the South Division. According with the technical-economical analysis conducted by personnel of Comalcalco Operation Unit and the South Division Engineering Sub-manager’s office, the following advantages are emphasized in comparison to the conventional collecting pans.

Safety: Minimized accident risk during installation and dismantling because of its lightweight plastic material. The anti-slip mat used on the rotary table reduced the risk of slip accidents on the floor. The system prevents foreign objects from falling down the annulus.

Environmental protection: A reduced risk of contamination on the cellar and the surrounding environment since the system operates as an enclosed system.

Operation: Reduced up to 70% of the installation and dismantling time.  Improved efficiency in fluids recollection.

Economical: An estimated savings of US$78,540 in installation and dismantling time during the technology test calculated as follows:

Cost per hour of drilling rig No. 339                = US$595

Number of jobs during the test                           = 4

Time savings per installation                             = 24 hours per job

Time savings per dismantling                            = 9 hours per job

Savings per installation                                        = 24 x 4 x $595 = US$57,120

Savings per dismantling                                       = 9 x 4 x $595 = US$21,420

Total savings                                                             = US$78,540

Savings of US$483,740 in fluid costs were reported (Table 1).

Table 1: Volume of fluids recovered (1,209.35 m³ ) * (USD$400) = USD$483,740

The second zero spill technology assessment was conducted in partnership with Akita Drilling and Talisman Energy on a drilling rig assessed over the majority of its drilling program. Jacques Whitford Environment was contracted to provide an independent environmental, health and safety assessment of the system. The following is an excerpt from the assessment report (trade names have been removed):

“This assessment is qualitative in nature and uses a scoring system developed by Jacques Whitford Environment Limited to reflect technical input from the field drillers and consultants using the equipment, as well as an independent audit conducted by Jacques Whitford Environment Limited.

In general the Katch Kan Zero Spill System rated extremely well in all three areas. All of the scores were marked out of 100 with 100% being the Maximum Attainable Score in any category. In addition, each component was weighted according to its significance in each of the three assessment categories.

Jacques Whitford rated the Zero Spill System as follows:

• Environmental protection: 99%
• Health and safety: 98%
• Economic benefits: 94%

Akita Drilling and the consultants rated the zero spill system as follows:

• Environmental protection: 97%
• Health and safety: 85%
• Economic benefits: 72%

The environmental protection component was rated very high by all parties, indicating that the system achieved its goal of capturing drilling fluids on the drill rig. Health and safety was also rated high by all parties with main differences occurring with the Katch Mat, the Adjustable Containment Enclosure, and the Second Stage Low Profile Katch Kan where the drillers and consultant scored these components lower than Jacques Whitford.”

Another positive, long-term achievement of zero spill technology continues to be the overall progression of the industry toward sustainable development. The implementation of the technology into best practices in pollution prevention and health and safety standards continues to direct upstream oil and gas activity to minimizing waste, not just managing it. The more oil and gas companies and drilling contractors that go “zero spill,” the more significant the strides will be toward the protection and enhancement of the environment and the communities where these activities occur.

This article is based on “Minimizing Environmental Footprint by Utilizing Prevention Technology,” SPE 124235, copyrighted by SPE and presented at the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, La., 4–7 October.

References:

Alberts, S. (2008, June 24). Obama’s fight against ‘dirty oil’ could hurt oil sands. The National Post. Retrieved from http://www.nationalpost.com.

The Ethical Funds Company. (2008). Winning the Social License to Operate Resource Extraction with Free, Prior, and Informed Community Consent. Retrieved June, 2009, from https://www.ethicalfunds.com/SiteCollectionDocuments/docs/FPIC.pdf.

Holliday, George H., “Environmental/Safety Regulatory Compliance for the Oil & Gas Industry’; p. 146. PenWell Publishing Company, Tulsa, Oklahoma, United States; 1995.

Schlumberger Excellence in Educational Development (SEEDS): Science Watch, “Drilling Fluid Environmental Case Study: The Hibernia Project”; Retrieved June, 2009, from http://www.seed.slb.com/subcontent.aspx?id=3092.

Alberta Environment, “Upstream Oil & Gas Reclamation & Remediation Program’; R&R/03-1, Edmonton, Alberta, Canada; August 2003.

Well cementing operations in South Texas tend to present a number of challenges to those responsible for constructing oil and gas wells. For instance, the temperatures and pressures at which the cement needs to be placed can be extreme, routinely exceeding bottomhole static temperatures of 300°F and pore pressures requiring fluid densities of 17 lbm/gal or greater to maintain well control. These extreme conditions can present challenges not only during placement of the cement slurry in the wellbore but also later to the set cement sheath during the life of the well.

To effectively meet these challenges, well operators in South Texas have been using high-density cements that have been mechanically modified so the set cement will be more elastic and resilient. Advanced diagnostic software is used to predict well situations where these cements are required.

Currently, high-density elastic cements (HDEC) have been placed in more than 40 wells in southern Texas, and the use of these sealants combined with diagnostic software has become routine.

This article discusses the challenges cementing high-pressure, high-temperature (HPHT) wells in South Texas, then details the best practice life-of-the-well solutions that have been applied.

BACKGROUND

South Texas has long been known for its HPHT reservoirs where drilling can prove a formidable exercise. In addition to difficulties dealing with high pressures and temperatures, low-pressure zones can be present.

In recent years, well designs have also become more complex as fields mature and operators search for new sources of oil and gas. Cementing the casing and liner strings in place in these wells is a critical phase in the well-construction process. The cement sheath is vital in that it protects and supports the casing and delivers the necessary zonal isolation for the well.

Once the well is completed, a new set of challenges that can stress an initially competent cement sheath are encountered. For example, some South Texas HPHT wells require high-pressure fracturing operations to unlock their full production potential, and in other wells, the heavy-weight drilling fluid with which the well is drilled is swapped out with lightweight brine at some point during the well completion process. In both cases, the loads imposed on the cement sheath can be extreme, potentially leading to debonding and even the catastrophic failure of a conventional cement sheath.

When this occurs, the situation generally can not be effectively remediated, and an operator might lose a costly wellbore. To address this problem, in 2006 it was identified that HDEC, designed to behave more elastically than conventional, brittle cements, can be applied to HPHT wells in the area with success. Use of HDEC has since become widespread in South Texas. Presently, HDEC have been placed for eight operators on 47 occasions in the area at temperatures up to 448°F and densities up to 18.9 lbm/gal.

WELL CONDITIONS

Many of the key plays in South Texas are HPHT, and two typical plays are the Yegua and Cook Mountain oil and gas plays. The Yegua play is defined by sandstone reservoirs that produce oil and gas from sandstones and deep, overpressured reservoirs in a band across the western Gulf of Mexico. The Cook Mountain sandstone gas play is defined by sandstone reservoirs that produce gas from structural traps across the western Gulf. The sandstones in both of these plays are generally characterized as having high permeability and porosity (Table 1).

Temperature gradients in the Yegua and Cook Mountain formations range from 1.4 to 2.1°F/100 ft. Most wells drilled into these sands come on production after being perforated with tubing-conveyed perforation (TCP) guns and flow naturally because of the high permeability of the sands.

One significant drilling challenge is insufficient borehole pressure integrity, especially when cutting through depleted zones intermingled with higher-pressure intervals. Shales and/or sands weakened by depletion, leaking faults or unfavorable rock properties result in lost returns when mud weights are close to pore and fracture pressures.

In one field, for example, oftentimes the target sand is normally pressured with overpressured shales above and below the sand, with some faulting present. Setting a casing string to isolate normal-pressure zones from high-pressure zones can be problematic if the faults exist at the casing shoe and the cement sheath does not provide a good hydraulic seal. Additional casing strings are often set to allow drilling to continue with narrow margins between pore- and fracture-pressure profiles. These narrow margins can create potential well control issues while construction of the well is in progress.

These conditions can also drive the selection process for the drilling fluids to use in these wells. Oil-based mud (OBM) systems provide definite advantages, generally delivering improved shale stability and clay control, reduced pore-pressure transmission, less differential-sticking tendencies, higher rates of penetration, and better lubricity to minimize torque and drag.

However, these fluids are often a costly solution with regard to disposal, lost-circulation issues and regulatory/environmental considerations. Therefore, when there are small differentials between pore pressure and fracture-initiation pressure, operators in South Texas prefer to use conventional water-based mud (WBM) below the intermediate casing string to better combat losses and hole ballooning, even though larger washouts are possible with WBM. Hole ballooning is defined by the walls of the well expanding outward because of the increased pressure during pumping. When pumping stops, the walls contract and return to normal size, forcing excess mud out of the wellbore.

Generally, wells drilled in fields by this operator follow a well plan commonly used throughout South Texas. Typical wells are drilled between 11,700 ft and 16,000 ft total depth (TD), with bottomhole temperatures ranging from 270°F to 340°F.

Surface casing

Surface casing is set at depths between 2,500 ft and 5,000 ft measured depth (MD), covering shallow lost-circulation and fresh-water zones. Surface casing depth and cement properties are defined by the Texas Rail Road Commission.

Intermediate casing

When drilling continues below the surface casing, higher bottomhole pressures often require a heavier mud. The heavier mud can break down weak zones, causing severe lost-circulation problems. To protect these weak zones, an intermediate string of casing is set at depths from 10,000 ft to 13,000 ft MD, just above or below the top of the nearest high-pressure formation.

The intermediate hole section can have multiple sand sections that can cause the casing to differentially stick before reaching TD. Good centralization is therefore important, as is running the casing to bottom as fast as possible, and when on bottom, not moving the casing. The intermediate string of pipe is cemented with tops of cement varying.

The top of cement (TOC) on an intermediate casing design oftentimes must allow for annular pressure to dissipate into the formation because hot mud passing up the drill pipe/casing annulus can cause fluid behind the intermediate casing to heat up and expand. This expansion has the potential to cause casing collapse; therefore, having a TOC at a depth below the previous casing is generally desired on HPHT wells.

The intermediate casing cement job typically requires an optimized spacer design and high displacement rates to maximize mud-displacement efficiency.

Production casing

On completion of the intermediate casing cement job, the drilling fluid density is increased, the well is drilled to TD, and production casing is set and cemented. The production casing cement sheath is required to effectively isolate water zones from pay sands. Sometimes a contingency drilling liner might be required in the process of drilling to TD if either a low-pressure or higher-pressure zone is encountered, compromising borehole-pressure integrity. This leads to the undesirable effect of reducing the diameter or drilling further and downsizing the well.

Operators in South Texas are implementing many new technologies as they strive to effectively exploit HPHT reservoirs. These include underbalanced drilling and drilling with casing to avoid associated problems with the intermingling of high-pressure and depleted zones, novel lost-circulation curing techniques and mechanically modified cements.

WELL INTEGRITY

The largest specific challenges these conditions create for those tasked with placing an effective cement seal in HPHT wells are:.

• High equivalent-circulating densities (ECDs) are created when the densified fluids required for well control purposes are pumped into the well, often leading to formation breakdown, followed by annular fluid loss in the fractures created that can potentially lead to well-control issues.
• After high-pressure well stimulation and production, casing failures can occur if the cement sheath that has been placed is incomplete or does not possess the requisite mechanical properties to withstand the high differential pressures to which it is subjected.

To combat the first concern, accurate pre-job dynamic-hydraulic computer simulations are important to assess whether the ECD throughout the open-hole annular area will stay below any known weak-zone fracture gradients. The narrow windows between those fracture gradients and the high mud weights can make this task particularly difficult. Obtaining the most up-to-date wellbore- and drilling fluid parameters for the simulations is imperative if a successful outcome is to be achieved. Like all computer models, the worth of the output is based on the quality of the data input into the model.

Once the wellbore definition is known, the next piece of the puzzle is the accurate modeling of fluid viscosities, one of the most prominent factors in the calculation of downhole ECDs. A variety of rheological models are available, such as Bingham plastic, power law and Hershel Bulkley. Each model has a different effect on the ECD. Choosing the right model is not as easy as requesting a specific plastic viscosity (PV) and yield point (YP), the two parameters specifically associated with the Bingham plastic model.

Methods are available today that will convert rheometer data into the best-fit model for any specific situation, enhancing the way downhole ECDs are calculated and helping lower the chance of losses caused by inadvertently fracturing the open hole during drilling and cementing operations.

Traditionally, the success or failure of a primary cement job was judged on its capability to safely place the designated volume of cement at a predefined depth in the annulus. Cement bond logs have also long been available as a tool with which operators can make an initial assessment of the bond between the cement sheath and the casing string.

However, the industry is now beginning to recognize that the success of a cement job should be based on the cement sheath’s ability to maintain zonal isolation throughout the life of the well. In the HPHT wells of South Texas, the set cement sheath is subjected to an extreme range of temperatures and pressures through completion, fracture stimulation and production cycles. Considering most of these wells are drilled with heavy-weight drilling fluid and cemented with even denser slurries, the pressure drop experienced inside the casing when swapping out to the much lighter completion fluids used can create a large amount of stress on the cement-casing bond, potentially leading to debonding issues.

In a number of cases, wells might also be fracture-stimulated directly through the cemented casing, creating a large cooling effect on the cement sheath combined with a large increase in pressure. These extreme conditions have led to several casing failures in South Texas because of the inability of conventional, heavy-weight cement to maintain its integrity during these cycles, often resulting in debonding from the casing or shear deterioration in the cement sheath. Once it has failed in this manner, the cement sheath might no longer provide zonal isolation; instead, it can act as a conduit for formation fluids to apply pressure to the casing, ultimately resulting in casing collapse.

Figure 1 illustrates a stress analysis on conventional heavy-weight cement. Both the completion (green) and high-pressure fracture-stimulation processes (blue) lead to complete debonding of the cement sheath from the casing.

For example, Figure 1 shows the results of an analysis performed on a conventional cement sheath in a HPHT well in South Texas.

These results illustrate how both the completion and high-pressure fracture-stimulation processes lead to complete debonding of the cement sheath from the casing. These results are typical for HPHT wells when cemented with conventional cements. To help prevent this, operators tasked with constructing HPHT wells should more closely evaluate solutions for the life of the well, paying particular attention to a stress analysis on the set cement sheath.

LIFE-OF-WELL SOLUTION

A number of methods can be used to enhance the mechanical properties of a set cement sheath to help prevent damage and potential failure during the life of the well. With any of these methods, the ultimate goal is to create a more elastic cement sheath by lowering the Young’s modulus and increasing the Poisson’s ratio.

One option is to foam the cement using nitrogen. One way of describing the effect of the nitrogen in the set cement is that the nitrogen bubbles act like “cushions” to help absorb the change in stress created during operations on the well. Foamed cement has been used in HPHT wells in the Gulf of Mexico to good effect and in Texas on deep land wells for primary cementing since at least 1984.

Unfortunately, to create a foamed slurry at the density required to maintain well control in the HPHT wells of South Texas, the base slurry density would have to be more than 22 lbm/gal. It is technically possible to design cement slurries at such high densities; however, they become an impractical solution in this environment because of the extremely high viscosities created by first densifying the base slurry, then energizing that base slurry with nitrogen, further increasing the viscosity of the resulting foamed fluid.

Therefore, alternative means of enhancing the mechanical properties of the set cement sheath should be examined.

In recent years, it has been possible to modify the mechanical properties of set well cement with dry-blended additives, such as carefully selected elastomers. These additives are used to help make the cement more elastic than conventional cements and thus more able to withstand pressure cycles and stresses imposed on it without failing catastrophically. Other additive materials, such as fibers, are used to enhance the tensile strength of the set cement.

Figure 2 illustrates the same stress analysis as in Figure 1 but applied to high-density elastic cement (HDEC). Overall changes to cement properties resulted in a cement sheath that will maintain more than 80% capacity for the life of the well.

When designing HDEC, it is necessary to carefully select the correct ratio of mechanical-modification additives, heavy-weight additives and cement. HDEC are generally designed to possess lower values for Young’s modulus and friction angle and higher values for cohesion, tensile strength and Poisson’s ratio than conventional cements. Figure 2 illustrates the results observed when an HDEC is subjected to the same analysis as the conventional cement illustrated in Figure 1.

The overall changes to the cement’s mechanical properties resulted in a cement sheath that will maintain more than 80% capacity for the life of the well, dramatically better than results with a conventional cement.

To reiterate the concern related to high ECDs during placement of these heavy-weight slurries, all available tools should be considered when performing the cementing and casing design. Expandable liner hangers (ELH) have been successful in helping reduce the ECDs on production-liner jobs in South Texas. In Figure 3, the differences between an ELH and a conventional, mechanical liner hanger are highlighted. The key benefit of an ELH from a cementing perspective is the pre-expansion, larger flow area of the ELH, which creates less of a “choke point” in the flow path during the primary cement job than conventional liner hangers. This allows for greater pump rates to be achieved before maximum ECD restrictions in a wellbore are met. This translates to better mud removal, less chance that losses will be incurred, and all else being equal, a better quality of initial zonal isolation.

Figure 3: Key differences between the expandable liner hanger and the conventional liner hanger.

CASE STUDIES

The Yegua formation a key target reservoir in South Texas. Generally, when the Yegua is completed without any sand-control measures, the well requires periodic cleanout because of the accumulation of formation sand in the wellbore. Mechanical remediation involving gravel packs or vent screens and resin-coated fracture treatments have been used.

When the Yegua is completed without any sand-control measures, it can sometimes produce naturally without making formation sand; however, at some point, the bottomhole flowing pressure (BHP) might be drawn down to the extent where the critical-failure stress might be reached in the rock matrix and the reservoir collapses, potentially point loading the cement and casing and causing it to fail.

As noted previously, debonding and shear deterioration caused by high pressure differentials are also potential hazards that the cement sheath will face throughout its intended design life.

Operators have documented casing failures of this nature in South Texas HPHT fields. Casing failures occurred within six months to one year after the wells were put on production, leading to loss of production revenue, expensive remedial work, and even well abandonment.

One operator wishing to minimize the occurrence of such well failures considered all facets of their planned cementing operation for improvement opportunities. The cement bond logs of the failed wells in question before production had shown good zonal isolation; therefore, inadequate annular cement coverage was not considered to be the root cause. Instead, the mechanical properties of the conventional cement sheath were thought to be inadequate to withstand well completion and production operations. It was therefore decided to implement an advanced cement-job design approach to address this issue; an approach that considered the desirable mechanical properties of the cement sheath in addition to the necessary short-term cement slurry properties (i.e., gas migration prevention, fluid loss, 24-hour compressive strength, etc). The operator applied this approach, using HDEC, on 10 wells with success.

G #1 Well

A specialized finite element analysis-based diagnostic software package was used to assess the situation in the Cimarex G #1 well in Liberty County, Texas, to determine if a cement sheath of known mechanical properties would be expected to withstand planned well operations in that specific well. The conclusion was that a conventional, high-density cement sheath would likely fail under the loads imposed by planned well operations (Figure 1). Therefore, a more elastic HDEC, possessing the necessary mechanical properties, was designed that could be expected to withstand those operations without failure (Figure 2).

Figure 4: Wellbore geometry of Well G #1.

The G #1 wellbore geometry is provided in Figure 4.

The production interval was drilled with a 6 ½-in. bit at an inclination of 34.5° through the target formation sand, to a casing setting depth of more than 16,000 ft MD, with 17.5-lbm/gal OBM. Wireline logs were then run, including a multi-axis caliper. The caliper log estimated an average hole size of 7.92 in., with a couple of washed-out sections higher up the hole with IDs of 12 in. to 23 in. A tight margin existed between the pore pressure of 17.4 lbm/gal in this hole section and an estimated fracture gradient of 18.0 lbm/gal.

The BHST at TD was 296°F, and temperature-simulation software was used to calculate a BHCT of 240°F (Figure 5). Dynamic hydraulic-simulation software was then used to optimize the cement-slurry placement parameters so that the job design would be expected to control the zones with high pore pressure and, at the same time, not break down the formation. This work identified that the following fluid densities and volumes would be used: 50 bbl of 17.7-lbm/gal optimized rheology spacer (ORS) fluid incorporating suitable surfactants for OBM compatibility, followed by 117 bbl of 18-lbm/gal HDEC. The software indicated that these fluids should be able to be circulated into the wellbore safely at 3 bbl/min to achieve the planned TOC at 12,733 ft MD.

Figure 5: The cement-placement temperatures of Well G #1 as calculated by the temperature-simulation software.

Figure 6: HDEC properties for Well G #1.

Properties of the HDEC selected are shown in Figure 6.

The 117 bbl of HDEC was mixed to density in a cement pump truck and transferred to two 100-bbl capacity batch mixers. Simultaneously, 50 bbl of ORS were also batch-mixed. These fluids were then pumped into the well as planned. The top plug was dropped, and the cement was displaced with 11.6-lbm/gal calcium chloride brine at 3.5 bbl/min. The plug was bumped after a displacement volume of 119 bbl and final circulating pressure of 5,970 psi. The bump pressure was then increased to 7,200 psi. The actual job chart is provided in Figure 7. Tank straps indicated full returns throughout the cement job with no mud loss.

Figure 7: Well G #1 recording of the actual HDEC placement. Tank straps indicated full returns throughout the cement job with no mud loss.

An initial CBL (Figure 8 ) indicated good bonding and provided evidence that effective displacement efficiency was achieved during the cement job. The G #1 well was then completed and put on production. No remedial work was required, and no problems with well integrity have been reported.

Figure 8: Well G #1 extract from an initial CBL across the production zone.

BH #1 Well

The BH #1 well was drilled as an exploratory well in Hardin County, Texas, to test the Cook Mountain sand. This sand was found to possess economically productive pay, and a production liner was set. The well was drilled in a field where a high potential existed for production casing failures (collapsed pipe), caused by either formation subsidence or formation collapse occurring because of increased drawdown during well production. The BH #1 wellbore geometry is shown in Figure 9.

Figure 9: Wellbore geometry of Well BH #1.

A 6 ½-in. production hole was drilled with 17.4-lbm/gal OBM. The estimated pore pressure at TD was 17.2 lbm/gal, and the fracture gradient at the 7 ^5/8-in. shoe was 18.0 lbm/gal.

The 6 ½-in. open hole was logged, and an average hole size of 6.5 in. was estimated from the caliper log. The planned TOC was 11,590 ft MD. As with the first case study, a tight margin between pore and fracture pressure existed. A 4 ½-in. production liner was therefore selected as the production string to reduce ECDs during the cement job while still being large enough to accommodate well completion requirements. An expandable liner hanger was also used to help reduce ECD during the running and cementing of the liner string.

Dynamic hydraulic-simulation software was again employed to help optimize pump rates and fluid rheologies for maximum mud displacement. From this work, it was decided to cement the well with 50 bbl of 17.7-lbm/gal ORS fluid, incorporating suitable surfactants for OBM compatibility, followed by 35 bbl of 18 lbm/gal-HDE cement to be pumped in the well at 3 bbl/min.

For this well, the HDEC also incorporated an in-situ gas-generating, anti-gas-migration additive because the simulation indicated that a severe gas-flow potential condition might exist in the well at job completion. HDEC properties are shown in Figure 10.

Figure 10: HDEC properties for Well BH #1.

After the 4 ½-in. production liner was run to TD, circulation was established to condition the 17.4-lbm/gal OBM at a maximum rate of 3 bbl/min. At this time, only partial returns were noted. The HDEC slurry and ORS fluid were prepared in individual batch mixers. These fluids were then pumped at 3 bbl/min. The drill pipe dart was then dropped, and the cement was displaced at 3 bbl/min with 17.4-lbm/gal OBM. The plug was bumped after 178 bbl of displacement, at a final circulating pressure of 1,050 psi and bump pressure of 1,698 psi.

The operation of expanding the liner hanger was then conducted and was successful. There were partial mud returns for the entire cement job. The actual job chart is provided in Figure 11.

Figure 11: Well BH #1 recording of the actual HDEC placement.

A cement bond log of the production liner indicated excellent bonding (Figure 12). The well was completed and put on production. No remedial work has been required on this well, and no problems with well integrity have been reported.

Figure 12: Well BH #1 extract from a cement bond log across the production zone.

BEST PRACTICES

Figure 13: The design of the yield stress analyzer is simple, but it is unique in its accuracy for measuring volume average shear rate versus stress data, as well as physically measuring the actual YP of a fluid system.

As noted previously, personnel in the southern Texas area have had the opportunity to use the diagnostic FEA software and deploy HDEC in numerous wells. They have developed a set of work methods and best practices for the successful application of this technology:

• While mechanical-property enhancing (MPE) admixtures can easily be added to cement systems, care should be taken that other slurry properties are not adversely affected. Some MPE admixtures have secondary effects that should be taken into consideration so that when the cement sets solid, the admixtures can provide the desired enhancement. For example, some MPE admixtures might, on their own, increase the rheology of a cement slurry and can also affect how the rheology is measured.
• Rheological measurements of HDEC in slurry form can be complicated by the size of the MPE admixture particles used and the clearance between the bob and sleeve of the standard rotational viscometer. In these cases, a special yield stress adapter (YSA) (Figure 13) is recommended. The YSA readily and accurately measures the yield stress of various fluids, such as particle-laden fluids. It is a special bob/sleeve combination that readily converts a Fann 35 viscometer to handle fluids with particulates, such as cement slurries with MPE admixtures, etc.

The design of the YSA is simple, but it is unique in its accuracy for measuring volume average shear rate versus stress data, as well as physically measuring the actual YP of a fluid system while using the standard Fann 35 viscometer equipped with a No. 1 spring. The geometries of the YSA bob (stator) and YSA sleeve (rotor) are designed so that particles of a wide range of densities can easily be volumetrically suspended during rheological measurement.

• When HDEC slurries are placed downhole at elevated temperatures, in common with other HPHT slurries, they can experience “thermal thinning.” Cement designers should be aware of this and guard against it, while still ensuring that the slurry does not exhibit any excessive viscosity that might inhibit mixing on the surface.
• Slurry stability is always critically important, and a well-simulation slurry stability test is performed on the cement slurry at HPHT conditions in an effort to detect any settling tendencies.
• The components of HDEC should ideally be dry-blended in the bulk plant and transferred on location.

Industry-recognized HPHT cementing best practices are also applied to help ensure that the chosen HDE sealant is placed in the wellbore annulus, where it is supposed to be, safely and efficiently. For example:

• When mixing slurry, extensive laboratory testing is done to help ensure that the slurry exhibits the right properties at surface and downhole conditions. Test conditions also reflect field-mixing technique, as some additives are sensitive to shear. For small volumes of cement slurry where a batch mixer is used to homogeneously mix the slurry, for example, the batch-mixing portion of the operation is usually simulated by stirring the slurry in a consistometer for the appropriate period at ambient temperature and pressure to impart an appropriate mixing energy.
• Fluid loss requires the use of a stirring fluid-loss cell in most HPHT situations to conduct the test using the actual temperature schedule. An API fluid loss of 70 cc or less in 30 minutes is acceptable. Most cement slurries tend to lose water to formations as the cementing operation is being carried out. Dehydration of the cement might result if the fluid loss is not controlled, and slurry movement can become difficult.

In cementing deep liners, the loss of fluid from a cement slurry can become a more serious problem than it is on long strings of casing. Because of little clearance between the liner and the wellbore, excessive loss of fluid from the slurry might cause bridging of the annulus and result in termination of the operation before the cement is in the desired position. In most cases, it is not necessary to completely prevent any loss of fluid from the cement slurry; rather, it is desired to control the amount of fluid that is lost.

• When dealing with gas migration, in many HPHT wells, pore pressure and fracture pressures are close to each other, which tends to increase the potential for gas migration. Gas can potentially enter the wellbore and flow up through or around the cement column from an overpressure zone to the surface or into a lower-pressured zone up the wellbore.

The likelihood that gas might flow up through the unset cement, if nothing is done to inhibit this flow, is determined by the gas flow potential (GFP). The GFP is used to determine the severity of the wells potential to experience annular gas migration problems. The GFP can be calculated from the following equation:

Preventing gas migration can be accomplished through slurry modification, job design changes, or a combination of both. To help prevent the formation of a gas channel in the unset cement, conventional slurries can be modified in five ways: decreasing volume losses, extending zero gel time, decreasing transition time, adding gas influx preventing materials, and/or increasing slurry compressibility.

To help prevent the formation of a gas channel in unset cement, the job design can be modified in four ways: decreasing effective column height, increasing overbalance pressure, interfering with the gellation process, and/or drilling a larger diameter hole.

• When dealing with job monitoring/execution, real-time job monitoring and data acquisition is extremely important for HPHT cement jobs. Parameters such as ECD, pressure, flow rate and fluid density can be captured by real-time data acquisition software at the rig site, allowing on-the-spot decisions to be made in the job execution to facilitate successful placement of cement.
• When dealing with compatibility testing, it is well known that the contamination of cement slurries with drilling fluids can cause severe problems, such as high viscosities, short thickening times, or failure of the cement slurry to develop sufficient compressive strength. Even the intermixing of the spacer or flush ahead of the cement slurry with the drilling fluid can, if incorrectly designed, possibly cause problems. It is therefore necessary that all fluids that can interact with each other downhole be compatible.

Compatibility testing of these fluids is done before a cement job, and if the fluids cannot be made compatible, job-design changes can be made, whereby the possibility of the two incompatible fluids coming in contact with each other is minimized.

• When dealing with mud removal, the tight pressure constraints found in HPHT wells in southern Texas mean that the desired density and rheological hierarchies are sometimes difficult to achieve without exceeding formation-fracture pressure. Therefore, the importance of other good drilling and cementing practices, such as conditioning the drilling fluid correctly, casing centralization, pipe movement when possible, and good spacer design all should be considered and implemented to increase mud-displacement efficiency.

CONCLUSION

In 1990, cement-sheath stress failure was identified as a leading cause of wells failing after they have been placed on  production. In 1999, FEA-based software became available, as did a methodology that could be used to diagnose whether a cement sheath with certain mechanical properties might be expected to fail as a result of those loading conditions.

In 2003, the application of foamed cement to a HPHT well in the North Sea because of its superior mechanical properties and ability to better withstand stress failure was detailed. In 2006, workers described the application of high-density, mechanically modified cements in south Texas to solve HPHT well failures.

This technology has seen widespread application in South Texas. HDEC have been placed in wells in the area on 47 occasions to date. Of those 47 instances, the authors are aware of only one case of a wellbore in which HDEC was applied and the wellbore still failed. In that case, casing collapse was noted after significant sand production and the creation of a void space behind the cement, and point loading was suspected.

Acknowledgements: The authors thank the management of Cimarex Energy and Halliburton for their support and permission to publish this paper.

This article is based on “The Application of High-Density Elastic Cements to Solve HPHT Challenges in South Texas: The Success Story,” SPE 122762, copyrighted by SPE and presented at the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, La., 4–7 October.

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Whether a well is being re-entered after having been abandoned for some time or it simply needs to be repaired to be functional, many operators choose to cement a new smaller outside diameter (OD) casing string inside the old one. Previously abandoned wells have been re-evaluated and found to respond to fracture stimulation using newer methods; however, to accomplish this, the casing string must have integrity. Casing integrity is also of significance in view of state regulations.

The challenges of this type of operation are many. One is to avoid excessive surge pressures while running the new casing. This means that on many occasions, running rates of the casing may have to be approximately 1 ft/sec. Excessive surge pressure can fracture a formation of interest, making it difficult to obtain the desired production rates.

Another challenge is to match casing size for stimulation with achieving successful cement isolation of an annular space. Smaller-diameter casing will result in increased friction pressure and therefore treatment rate restrictions.  Stimulation may require multistage completions to be effective. The increased cost of stimulation must be balanced with the need to achieve cement isolation.

Presented here are the analyses of various scenarios examining fracture gradient, old casing burst pressures, fracture stimulation rates and pressures and equivalent circulating densities of potential cement slurries. Case histories are used to illustrate these scenarios and present situations in which the cost of the cement pumped versus what should have been required is compared. Also presented are the operational and cost differences regarding stimulation as a function of casing internal diameter. In one case, over three times the quantity of cement that should have been necessary to achieve circulation back to surface was pumped without circulating.

BACKGROUND

Several situations exist where a smaller OD casing is cemented inside an existing casing: re-entry into a previously abandoned wellbore, repair of an existing casing or to facilitate drilling deeper. Re-entry and repair are of primary concern since these typically involve a smaller annular space between the two strings of casing. The concerns are, first, getting a good cement job and, second, having sufficient internal diameter (ID) to facilitate future stimulation treatments.

In the last few years, re-entries have been significant in West Texas and southeastern New Mexico. They provide the opportunity of avoiding excess drilling costs to obtain an economically producing property. However, the ultimate goal is to have a producing well with a good hydraulic seal across all rock strata and therefore control of all fluid movements downhole.

This is only accomplished by filling all of the annular space between the old and new casings with cement. Many of these re-entries require hydraulic fracture stimulation to create an economic producer. To accomplish this, operators maximize the flush joint liner string diameter. This minimizes the annular space between the existing casing and the flush joint liner. When cementing these narrow annular spaces, the excess of cement pumped – the amount over what should be required between two casing strings – is much greater than expected. This has often been greater than the excess of a primary cement job where casing is being cemented in a newly drilled wellbore.

Even then, with these excesses pumped, circulation of cement to a desired height behind the new casing, in many cases, is not accomplished, leaving one to wonder if the excess cement went into a pay zone. If it did enter a pay zone, then hydraulic fracture stimulation becomes increasingly important, and the well has a greater risk of resulting in lower production revenue than initially anticipated.

The cost savings on stimulation versus the increased costs of excess cement, potential of pay zones being damaged by losses of cement, possibility of not having hydraulic control of fluid movements in the wellbore and a lower-than-anticipated revenue stream make it a much higher-risk project than it would appear initially.

Casing repairs in West Texas and southeastern New Mexico are typically performed on injection wells where either water or a mix of water and carbon dioxide are pumped into a reservoir to maintain a sufficient pressure to facilitate increased production in offset wells.  Many of these wells were producers that have been converted to injectors. These producers are older wellbores drilled from 1955 to 1996.

When the production casing on many of these wells was cemented, only a sufficient amount of cement was pumped behind the pipe to give control over the pay zone for stimulation and production. On rare occasions, cement was brought to surface. Typically, 900 ft to 1,500 ft of cement was placed behind these casing strings. This meant that many corrosive water-bearing zones up-hole in the well were open, allowing the corrosion of the production casing, weakening it to the point of leaking and/or collapsing.

OPERATIONAL ISSUES

As mentioned above, a good cement job is one of the keys to achieving success on these operations. In addition, consideration must be given to the actual running of the new casing inside the old and the effect this may have on the old casing’s integrity.

Effect of circulation rate on annular pressure

A typical intermediate or production cement operation involves isolating casing set in open hole with an overlap of pipe inside of pipe at the upper portion of the hole. Cementing is designed to minimize the potential of the combined effect of hydrostatic pressure and friction pressure in the annulus from exceeding the breakdown pressure of the formation, resulting in lost circulation or fracturing the formation with cement.

Figure 1: Illustration of the effect of the pump rate and annular width on ECDs in the annular space for various rates and annular configurations. Included are typical surface and production configurations, as well as the slim-hole configurations presented in the case histories in this article.

Pipe and hole dimensions vary greatly. However, as a general rule, the inner diameter of the open hole or previous casing string is three or more inches larger then the outer diameter of the casing being cemented. The friction pressure caused by pumping cement in the annular gap between a 5.5-in. casing and a 9.0-in. hole is relatively small compared with the hydrostatic pressure of the cement.

A dynamic modeling program, based on API-adopted fluid dynamic calculations, has been in use for several years to determine the dynamic annular pressures or equivalent circulating density (ECD). This model was used to predict ECD under various conditions.

Figure 1 shows the increase in ECD per 1,000 ft of annular depth for various rates and annular configurations. Included are typical surface and production configurations, as well as the slim-hole configurations presented in the case histories of this article. A 14.8-ppg Class C slurry with fluid loss and dispersant was used for comparative purposes in the ECD calculations. This slurry is best modeled as a Bingham Plastic with a 30.5 cp Plastic Viscosity (PV) and a 0.1 lb/100 sq ft Yield Point (YP). Increasing rate from 2 bpm to 5 bpm in a 5.5-in. by 7-in. annulus will result in a 9% increase in annular pressures or ECD compared with the static column.

The same increase in rate will result in a 70% pressure increase in a 4.0-in. by 4.89-in. casing/casing annulus. Rates above 2 bpm may more than double the annular pressures in smaller annular gaps.

Effect of running casing on annular pressures

The industry has long recognized the increases in annular pressure resulting from running casing in the hole prior to cementing. A paper in 1974 provided methodologies for calculating this surge effect on open- and closed-end casing. Others have provided technical details for calculating dynamic surge pressures with high viscous forces in low clearance liner applications. Methodologies have been introduced to determine the maximum velocity for running casing without exceeding the fracture gradients.

Most of these later methodologies were mathematically rigorous, requiring the solution of coupled partial differential equations.

In 2003, a task force was formed to modernize the existing API recommended practice (RP) publications for cementing calculations. Their efforts resulted in the publication of the 2006 revision of RP13D. This included a review of the published algorithms for swab/surge calculations. The resulting recommendation was a simple and accurate process based on the methodologies published in 1974.

This article applies these correlations to estimate the effect of running new casing inside of old.

The majority of operators re-casing wells by running new casing inside old utilize a float shoe on the new casing string. This compounds the surge phenomena by forcing all of the fluid displaced by the OD of the new casing into the casing/casing annulus. This issue is much more significant when dealing with a narrow annular gap and old, weakened casing that already has leak points.

HYDRAULIC FRACTURING, CASING SIZE

Many stimulation treatments today are propped fracture treatments using a variety of fluids from slickwater to 40-lb crosslinked (XL) gelled water systems to create, propagate and transport proppant into the zone or zones of interest. Some of these are single stage treating a small interval; others are multistage covering several intervals. Others include a single stage covering a large interval using a “limited entry” technique.

All of these treatments could be pumped at high rates and, in the case of the last technique, very high rates. Casing choices in many cases are based on the treatments to be performed on the zones behind the pipe. Two criteria are yield strength and ID. These are important with regard to the stimulation injection rate and the surface treating pressure (STP) to get this rate. Other aspects of this completion process are cost-driven. Higher hydraulic horsepower (HHP) required to pump the treatment may be significantly more expensive. Higher pressures also introduce a higher safety risk on location.

Figure 2: 20-lb crosslinked fracturing fluid pipe friction in various pipe IDs is illustrated.

In the case of a single zone to be frac’ed, the rate needed and the anticipated pressures associated with the creation of the fracture can be calculated, with the only variable being the pipe friction of the fluid. Figure 2 is an illustration of the expected friction per 1,000 ft of pipe, for a 20-lb XL fracturing fluid, at various injection rates. The different curves represent three of the potential casing IDs that might be chosen. For example, if 40 BPM was required for the fracture treatment of an interval at 5,000 ft, the expected increase in STP to treat down 3.5-in. casing rather than 5.5-in. would be 2,400 psi or the need for approximately 70% more hydraulic horsepower.

The need for a good cement job behind a liner is even more critical when the existing casing is known to be weak and a stimulation treatment will be pumped via the liner. If the cement is not brought up past the weak points in the existing casing, it may be difficult to hold pressure on this annulus. In this case, the maximum STP will be the yield point of the new casing above the top of cement (TOC).

CEMENTING CASE HISTORIES

Figure 3: Map of the wells studied.

Several injection wells in the San Andres formation of Yoakum County, Texas (Figure 3), have been re-cased over the years, running and cementing new 3.5-in. to 4.5-in. OD flush joint casing inside existing casings of 4.09-in. to 5.012-in. ID. Figure 4 shows a representative wellbore sketch.

The well on the left represents most of the wells being repaired, where the primary cement job left a great deal of exposed casing. The well on the right shows the liner being used for the repair and the cement not quite making it to surface, and again leaving some exposed pipe surface. Over 95% of these old casing failures were due to corrosion by water from zones (Red Beds and others) not covered with cement in the primary cementing operation.

Figure 4: The diagram on the left is typical of wells to be repaired, where the primary cement job left exposed casing. The diagram on the right represents what has happened on some occasions, with the liner being used for the repair and the cement not quite making it to surface, again leaving some exposed pipe surface.

The weak and/or leaking depths in these casing strings were from 400 ft to over 4,800 ft and generally consisted of many such points of weakness scattered between these depths.

The San Andres wells studied in the West Brahaney Unit (WBU) are perforated from 5,200 ft to 5,300 ft, those in the Starnes Unit from 4,990 ft to 5,020 ft. Operator A’s Well 1 has four perforated Wolfcamp intervals from 8,400 ft to 8,500 ft, 7,430 ft to 7,450 ft, 7,240 ft to 7,260 ft and 7,120 ft to 7,140 ft. In the WBU and Starnes Unit, once multiple leaks in the casing were identified, the well is plugged back temporarily using a cast iron bridge plug (CIBP) and, in some cases, sand, in order to keep cement off of the perforated interval.

Table 1 lists the wells evaluated in this study and the pertinent information. Table 2 lists the common cement systems used in the cementing operations. Table 3 gives specifics of the cementing of the new casing in four of these wells, which are the focus of the cement case histories. All of the new casings in this study were run in hole at approximately 1.0 ft/sec. The spud date, original TD, TOC of original primary cement job and existing casing weak points for the study wells are listed in Table 4.

Table 3:Focus Wells of Cement Study

RUNNING CASING

The annular pressure or ECD increase caused by running casing with a float shoe was evaluated at various running rates. Four wells recently “re-cased” in West Texas were used for this evaluation. The drilling mud was displaced with water prior to running casing in each of the wells. Actual running rates varied from 0.5 ft/sec to 1.25 ft/sec (Table 5).

WBU 137 had a total annular clearance of 0.95 in. For this configuration, the equivalent velocity in the annulus resulting from viscous drag and fluid displacement is 2.4 times the downward velocity of the casing. The calculated ECD at TD of running the casing at 1 ft/sec is 9.04 ppg (Table 4), 8% higher than the 8.34-ppg density of the fresh water in the wellbore.

Starnes 11-4 had a total annular clearance of 0.45 in. For this configuration, the equivalent velocity in the annulus resulting from viscous drag and fluid displacement is over three times the downward velocity of the casing. At the same running rate of 1.0 ft/sec, this smaller annular space has a calculated ECD at TD of 15.45 ppg, an 85% increase in pressure over a static column of fresh water.

CASE HISTORY 1

WBU 127 was originally completed in 1997. The original casing had an OD of 4.5 in. and a weight of 9.5 lb/ft. According to the well files, the top of cement can be estimated to be at approximately 2,500 ft. Over the years, the casing has been corroded and developed leaks from 896 ft to 909 ft and from 1,444 ft to 1,508 ft. The corroded casing had a combined leak-off rate across the two intervals of 1.25 bpm at 1,300 psi. To resolve this problem and restore wellbore integrity, the operator ran a flush joint liner with an OD of 3.5 in. and a weight of 9.2 lb/ft to 5,148 ft.

The liner was cemented in place with 200 sacks of lead followed by 75 sacks of tail slurry. The lead was a 50:50 blend of Class C cement and fly ash with 10% bentonite, 5% salt and a dispersant mixed at a density of 11.8 ppg. This slurry had a yield of 2.45 cu ft per sack.  The tail slurry was Class C cement with a fluid loss additive, 5% salt and a dispersant mixed at a density of 14.8 ppg. This slurry had a yield of 1.37 cu ft per sack. The total combined slurry volume was 592.75 cu ft. The calculated annular volume plus the 43-ft shoe joint was 127.81 cu ft; therefore, over 350% excess cement was pumped.

Figure 5: Density, rate and pressure during the cementing of WBU 127.

During the job, the surface treating pressure increased as expected (Figure 5). The annular pressures and ECD at the known weak casing depths were calculated using the dynamic modeling program previously described. The calculated pressures are given in Table 6 and plotted as ECD in Figure 6. As shown in Table 6, the ECD at the deepest known weak casing depth was over 26.27 ppg when the lead cement reached this depth. This high ECD can be attributed to the high friction pressure resulting from the 2.2 bpm displacement rate in a 3.5-in. by 4.09-in. annulus (Figure 1).

Figure 6: The calculated ECD at critical depths during the cementing of WBU 127.

The pressure did not exceed the 4,380-psi burst pressure of the existing casing but was sufficient to break down the formation behind the weak points and increase the holes in the corroded sections. As a result, the TOC as indicated by a temperature survey after the job was at 1,450 ft, 6 ft below the top of the deepest casing leak. Cement did not cover the upper points of existing casing leaks, making this new casing susceptible to the same corrosion that created the problems in the first place.

Figure 7 illustrates what the dynamic model shows for ECD at a depth of 1,508 ft, based on the actual job. Figure 8 illustrates one scenario where the mix and pump rates of the cement and the displacement rate are reduced and have a subsequent reduction on the theoretical pressure applied at that depth. Another alternative to reduced pump rates is to reduce the densities of the slurries (Figure 9). Keeping the ECDs below the breakdown pressures of the intervals of bad casing will assist in raising the cement higher in the annular space. The other alternative is to use a smaller-size liner and increase the annular gap. The idea is seen in Figure 10, where the job is modeled as in Figure 7 but with the cement being placed in a larger annular space.

Figure 7: The modeled ECD at a depth of 1,508 ft in WBU 127.

Figure 8: The modeled ECD at a depth of 1,508 ft in WBU 127 with adjusted mix and displacement rates.

Figure 9: Modeled ECD at a depth of 1,508 ft in WBU 127 with slurry densities and reduced rates.

Figure 10: Modeled ECD at a depth of 1,508 ft in WBU 127 with 3.5-in. liner inside 15.5-in. existing casing.

CASE HISTORY 2

The original J55 Grade casing in WBU 137 had an OD of 5.5 in. and a weight of 15.5 lb/ft. A casing inspection log was run from PBTD to surface. It showed severe internal corrosion below 4,100 ft, with holes at 4,364 ft, 3,900 ft and 1,850 ft. The decision was made to cement a 4-in. liner from surface to 5,097 ft. The liner was cemented in place with 300 sacks of Class C cement, with dispersant and fluid loss additives, mixed at a density of 14.8 ppg. The slurry yield is 1.33 cu ft per sack. The slurry volume was 399 cu ft. The annular volume was 236.35 cu ft, so the cement pumped was 69% in excess of what was required.

Figure 11: Density, rate and pressure during the cementing of WBU 137.

While cementing the liner in place at an average rate of 2.4 bpm, the surface pressure stayed below 1,200 psi (Figure 11). The calculated ECD across the corroded interval above 4,300 ft reached a maximum of approximately 17 ppg (Table 7 and Figure 12). The lower ECD compared with the previous case is due to the larger annular gap (0.95 in).

This resulted in an increase of the cross-sectional area by 90% over WBU 127. There were lower pressures, which resulted in the circulation of cement back to surface (34 sacks) and the isolation of the leaks in the old casing.

Figure 12: Calculated ECD at critical depths during the cementing of WBU 137.

CASE HISTORY 3

Figure 13: Density, rate and pressure during the cementing of WBU 17.

A 5.5-in. OD and 14-lb/ft casing was used on WBU 17 as the original casing string. The operator decided to restore the pressure integrity of this well by cementing a 4.0-in. OD and 10.6-lb/ft liner from surface to 5,115 ft.

The calculated annular volume for this well is 254 cu ft. A total of 400 sacks of Class C cement with dispersant and fluid loss additives were mixed at a density of 14.8 ppg for this job. The slurry yield is 1.33 cu ft per sack. This resulted in a slurry volume of 532 cu ft, or an excess of 109%.

The liner job was displaced at an average rate of 3.5 bpm (Figure 13). The resulting surface pressure reached a maximum of 3,500 psi as shown in Figure 13. The annular ECD at the bottom liner reached a maximum of 17.83 ppg (Figure 14) while the mid-point of the liner reached a maximum of 17.71 ppg (Table 8). As in the case of WBU 137, the larger annular gap (1.015 in.) allowed for lower friction pressures and therefore less pressure applied to the existing wellbore, which resulted in approximately 84 sacks of cement being circulated to surface.

Figure 14: Calculated ECD at critical depths during the cementing of WBU 17.

STIMULATION, ECONOMIC CONSIDERATIONS

Operator A’s Well 1, listed in Table 1, is an example of a well with a liner inside of an existing casing that is subsequently frac’ed in multiple stages in the Wolfcamp. Figure 15 is a plot of the cement job rate, pressure and density, and Figure 16 is the plot of of the ECDs at two depths. Figure 17 presents the rate, pressure and proppant concentration pumped on one of the fracture stages of the Wolfcamp formation in this well. Figure 18 compares how the friction pressure for the 25 bpm frac injection rate would vary depending on casing size. To pump the job down the 4-in. instead of the 5-in. casing means that the STP will be over 200% higher due to the increased friction. If the treatment is pumped down a 3.5-in. liner, the HHP requirement would be over 600% more. Figure 19 expresses this same information in terms of cost for the increased HHP, assuming that STP does not exceed 5,000 psi.

Figure 15: Density, rate and pressure during the cementing of Operator A’s Well 1.

Figure 16: Illustration of the rates, pressures and densities during the cementing to the liner in Operator A’s Well 1.

Figure 17: The rate, pressure and proppant concentration during Stage 3 fracture treatment of the Wolfcamp in Operator A Well 1.

Figure 18: Comparison of the pipe friction vs. pipe size for a 20-lb crosslinked fluid at 25 bpm.

Figure 19: Comparison of HHP costs (non-discounted) for frac at 25 bpm at a pressure of less than 5,000 psi.

There has to be a risk-based balance with cementing costs. Figure 20 compares the non-discounted cement costs of four of the wells studied. Of these, 50% circulated cement to surface, but this cement circulated was on average 15.5% of the excess pumped. Changes in procedures, slurries and variance in annular gap in the wells studied over the last few years have yielded improvements (Table 9), but more needs to be done in designing future wells where re-casing is a necessity.

Figure 20: A cost comparison of cement pumped versus cement required for the four wells. The cement circulated was on average 15.5% of the excess pumped.

It is shown that when the annular gap was bigger and displacement rates were reduced, circulation of cement to surface was more common. However, as the annular gap was reduced, even slowing down displacement rates did not help to achieve circulation but did achieve a higher TOC.

CONCLUSIONS

1. Successful placement of cement in “re-cased” holes is dependent on pre-planning and pre-job modeling:

2. Assumptions that are normally valid in conventional cementing applications should not be used in narrow annulus re-casing applications. It is critical to analyze the cement job with a dynamic modeling program as part of the design process. Normal mixing and displacement rates may cause annular pressures to exceed casing burst or collapse strengths. A displacement rate as low as 1.0 bpm could cause downhole pressures to exceed formation or pipe limits.

3. High surge pressures can be caused by running casing at the “usual” rig rate. A dynamic modeling program may be used to determine the maximum annular fluid flow rate to avoid exceeding the casing burst or formation breakdown pressure behind the bad pipe. Once this is determined, a spreadsheet calculation may then be applied to determine how fast casing may be run to avoid exceeding this maximum annular rate.

4. Selection of liner OD and ID for re-casing existing wells is dependent upon a balance of costs and the physics of what will be done in the future in the area of stimulation. The choice of single-zone, multizone or limited-entry stimulation and the associated pump rates can all be significantly impacted by the flush joint liner design.

Acknowledgment: The authors wish to thank BJ Services Company USA, and Walsh Petroleum for allowing them to present this information. They would also like to thank Gerald Benton and Dean Olson with BJ Services and Robert Meritt with Walsh Petroleum for their assistance in gathering information.

This article is based on SPE 124381, “Wellbore Re-entries and Repairs: Practical Guidelines for Cementing New Casing Inside Existing Casing,” copyrighted by SPE and presented at the 2009 SPE Annual Technical Conference and Exhibition, held in New Orleans, La., 4–7 October.

References:

1. Purvis, D.L. and Gregory, G.:”Utilizing A Field Computer System During Cementing to Help Avoid Costly Workovers”; CIM 88-39-47; Journal of Canadian Petroleum Technology, Sept. 1990.

2. Purvis, D.L. and St. Clergy J.:”Eliminating the Unknowns of Primary Cementing With On-Site Verification and Post Job Analysis”; SPE 23991; Permian Basin Oil and Gas Recovery Conference, Midland Tx. March 18-20, 1992.

3. Purvis, D.L. and Smith, D.D.: “Real-Time Monitoring Provides Insight to Flow Dynamics During Foam Cementing”; SPE 24570; Annual Technical Conference, Washington D.C., October 4-7, 1992.

4. American Petroleum Institute: ”Recommended Practice for Testing Well Cements”; API RP 10B-2 First Edition July 2005, API Publishing Services, Washington DC: API.

5. Fontenot, J.E and Clark, R.K.:”An Improved Method for Calculating Swab and Surge Pressures and Circulating Pressures in a Drilling Well”; SPE 4521, SPEJ (October 1974) 451-62.

6. Mitchell, R.F.:”Surge Pressures in Low-Clearance Liners”; IADC/SPE 87181; IADC/SPE Drilling Conference, Dallas Tx, March 2-4 2004.

7. Rubiandini, R.S.:”New Formula of Surge Pressure for Determining Safe Trip Velocities”; SPE 64480; SPE Asia Pacific Oil & Gas Conference, Brisbane Australia, October 16-18 2000.

8. Bern P.A., Morton E.K., Zamora M., May R., Moran D., Hemphill T., Robinson L., Cooper I., Shah S., Flores D.V.: ”Modernization of the API Recommended Practice on Rheology and Hydraulics: Creating Easy Access to Integrated Wellbore Fluids Engineering”; SPE 98743, SPE Drilling and Completion (September 2007) 197-204.

9. RP 13D, Recommended Practice on Rheology and Hydraulics of Oil-well Drilling Fluids, fifth edition 2006, Washington, DC: API.

10. Cramer, D.D.:”Application of Limited Entry Techniquesin Massive Hydraulic Fracturing Treatments,” SPE 16189, SPE Production Operations Symposium, March 8-10, 1987, Oklahoma City.

Even as environmental agendas delay well permitting and cause other headaches, new opportunities may loom for “green” drilling. Two areas in particular present themselves – CO₂ geologic storage and geothermal drilling.

As Pritchard Capital somewhat breathlessly phrased it in a recent e-missive, “Geothermal is hot and getting hotter.” As previously reported herein, $90 million of US funding was designated for geothermal technologies. The funding is for work on conventional geothermal resources and for “enhanced” geothermal.

Longtime DC readers may recall “enhanced” geothermal from 1991, when Los Alamos invited IADC to organize a drillers’ delegation to tour the New Mexico facility and learn about “hot dry rocks” – now reborn with the rather more marketable moniker “enhanced” geothermal. In short, an injector and a producer are drilled into non-permeable, heat-bearing strata. The rock is fractured, tepid water pumped in and hot water produced to generate electricity.

A $500 million-plus annual bonanza in drilling and well services predicted in ’91 has yet to emerge. Even today, backed by fed funds, progress is shaky. One recent, well-publicized DOE-funded project in California’s Geysers by AltaRock Energy was suspended in early September after failures re-entering and deepening the first well. Each of AltaRock’s three redrill attempts ended in failure, the well collapsing and trapping the BHA. The company suggested several culprits – long-term injection, difficult geology, and the well rework itself. AltaRock would not comment to DC beyond the information on its website.

Steamy enthusiasm for geothermal exists outside the US. Two days before writing this column, IADC received a query for a deep-drilling land rig for a four-well geothermal project in northeastern Germany. According to Mr V Goebel, the local adviser, the site is near Schwerin. Related drawings and the e-mail address for Mr Goebel follow this article. “Our timeline becomes real as soon as we find the required drilling contract,” he wrote.

CO₂: A LOT OF GAS?

The other prospective green gusher for well services is CO₂ geologic storage. Suggestions for CO₂ disposal modes abound. Our industry has been injecting the stuff downhole in tertiary oil-recovery programs for decades. Kinder Morgan CO₂ alone delivers some 1.3 billion cu ft through 1,300 miles of pipelines. Much of this is produced from domes in the western US, ironic in an age of CO₂ terror.

Geologic storage also encompasses injection into coal seams and deep saline formations. (CO₂ semanticists quail at the term “aquifer injection,” stressing that only formations with non-potable reserves are targeted – more than 10,000 mg/liter total dissolved salts.) “Saline formations offer great potential CO₂ storage capacity,” states the US Environmental Protection Agency.

CO₂ is catching the attention of the industry. DC recently chatted with George Koperna of Advanced Resources International, co-chairman of an SPE CO₂ conference in November. “We’re talking about a potential for widespread development,” Mr Koperna told us. Details are available in video and text formats here.

EPA wants to be doubly – triply! – sure that nary a molecule of dreaded CO₂ escapes its subterranean tomb. Hence, standards for wells and reservoirs will be stringent, according to Mr Koperna. (One could be forgiven for thinking we were dealing with plutonium or PCBs.) “You have to prove it’s going to stay there,” Mr Koperna said.

Still, even though all CO₂ must be injected below the lowest drinking water aquifer, most of these wells don’t TD much below 3,500 ft or so – shallow depths.

Several geologic sequestration projects are ongoing, both via miscible recovery and geologic sequestration, including StatoilHydro’s Sleipner platform and the In Salah gas project in Algeria. A demonstration project of CO₂ injection for both tertiary oil recovery and CO₂ storage is the Weyburn Enhanced Oil Recovery Project.

In early October, US Energy Secretary Steven Chu just announced $1.4 billion-with-a-”B” for 12 projects to capture and store CO₂, including saline injection. C6 Resources will capture, transport and inject a million tons of CO₂ annually into a saline formation two miles underground – not so shallow, a $3 million DOE grant. Other recipients planning underground disposal include Praxair Inc, Shell Chemical Capital, ConocoPhillips and the University of Utah.

Finally, DOE announced that a partner has successfully injected 1,000 metric tons of carbon dioxide (CO₂) into the Mount Simon Sandstone, a deep saline formation that is widespread across much of the Midwest. Depths were 3,250 ft-3,550 ft.

While our industry finds itself at odds with much on the environmental agenda, silver linings might still exist. Perhaps these are two.

Click here for the EPA’s presentation, Geological Sequestration of Carbon Dioxide.

You can reach Mike Killalea at mike.killalea@iadc.org.

By Linda Hsieh, assistant managing editor

“I don’t mind failing so long as I can find out why and be certain that I’m not going to repeat that failure again. It has to teach me something that I’ll carry forward,” said Chevron MAXDRILL team leader Graham Mensa-Wilmot.

As a young man growing up in Ghana in the ’70s, Chevron’s Graham Mensa-Wilmot remembers PetroCanada putting up an offshore drilling rig near the coast where he lived. From the second floor of his high school’s library, he could always spot the rig and see the gas flares shooting up high into the sky. “I remember thinking, whoever’s doing that, that’s what I want to do when I grow up,” he recalled.

Driven by an inquisitive streak that was always prodding him to find out the unknown, Mr Mensa-Wilmot tried to discover everything he could about the flares. “I kept asking if there were people working there, and how someone could just put up a flare and go home. I kept asking lots of questions,” he said. “That’s how I got introduced to the oil and gas industry.”

After high school, he won a scholarship from the Romanian government and attended the University of Petroleum & Gas in the city of Ploiesti. Early in his first year, one professor compared a drilling engineer to a doctor whose patient he can’t see, can’t touch and can’t feel because it’s miles away and can’t talk – but it will let you know when it’s feeling bad. “That concept really impressed me about drilling engineering,” he said. He eventually completed both his bachelor’s and master’s degrees at the school.

After graduation, he went to work for Ghana National Petroleum Company as a drilling engineer and was put to work on the same rig he used to watch from his school library. Following this experience, he enrolled and did graduate research work at Texas A&M University. In 1988, Mr Mensa-Wilmot joined a Houston-based drilling services company called SlimDrill. For a couple of years, he worked as a directional driller on rigs operating in the Austin chalk.

“It was there that I got fascinated with drilling optimization and performance drilling,” said Mr Mensa-Wilmot. “I was never lucky, always drawing jobs around or during Christmas,” he recalled. “If we finished the job early, we got to go home, but we never finished on time. I got frustrated and started thinking, how can we do things better? How can we reduce our flat times so we can go home?”

His inquisitive streak kept kicking in, and he found himself fighting the routine of doing things in certain ways just because “that’s how it’s always been done.” He was always asking, “Why do it that way? How can we make it better?”

As part of his efforts, Mr Mensa-Wilmot began looking into drilling applications and drill bit technologies, especially those related to PDC bits. Around the same time, researchers in different companies started extending their activities to include the impact of vibrations on bit and drilling performance. Mr Mensa-Wilmot decided that he wanted to be part of this effort by putting his drilling background to use. To him, the old saying “If it ain’t broke, don’t fix it” does not hold water. Rather, it should be: “If it ain’t broke, make it better, and if it is broke, fix it.”

“I started my career in the field, so I always want to not just do new things but do new things that would improve work in the field,” he said.

Mr Mensa-Wilmot has worked at major drill bit companies in positions of increasing responsibility. He has accrued more than 22 patents, primarily related to drilling applications, technologies and PDC bits. He has also authored over 30 technical papers on the same subjects.

He joined Chevron’s performance improvement team two years ago and is the current leader of the MAXDRILL Team, which focuses on performance drilling.

He believes that amid the recent drilling boom, the industry lost its understanding of applications and what performance drilling required, putting a halt on important progress in terms of reducing overall drilling costs. “We have more tools and means of analyzing applications today than (15 to 20 years ago)… but we’re not capitalizing on those tools,” he said. “You need to understand the application, the drive mechanism, the BHA and make sure you are developing an appropriate solution based on the challenges of the project.”

Mr Mensa-Wilmot hopes that, over the next few years, the MAXDRILL team’s work will help the industry to understand what “performance drilling” actually is.  “Everybody talks about it and everyone has a different definition… I’m not saying my idea is right, but I want to initiate a debate, where we begin to question what we have always done. I want people to think about it and begin to find ways to improve, based on what they’re trying to achieve. We cannot improve by always doing it in the same way, we have to challenge ourselves and also expect more.”

William C (Kurt) Hoffman has been appointed senior vice president and chief operating officer of Seahawk Drilling, whose spin-off from Pride International was completed in late August. Since 2004, Mr Hoffman has been VP worldwide marketing at Noble Corp, where he was also VP Western Hemisphere operations from 2000 to 2004. Prior to Noble, Mr. Hoffman held several management positions with Triton Engineering Services, including president and VP international operations. He started his career in the drilling industry with Zapata Offshore Company.

Baker Hughes to open chemicals plant, operations center

Baker Hughes will open two facilities in Canada this fall to serve operators in the oil sands and other northern Canadian fields: an oilfield chemicals plant in Leduc and a multi-discipline operations center in Fort McMurray.

The 41,000-sq-foot chemical plant houses an oil sands laboratory, a water-based blending vessel, a mixer for sensitive chemicals, an 18-tank storage farm and rail access and warehouse space. The facility will have water treating and fluid separation chemical production capabilities to support heavy oil and oil sands mining and steam assisted gravity drainage (SAGD) projects.

The operations center in Fort McMurray will provide dedicated warehouse and staging areas to support oil sands projects in the area. It will house a full range of Baker Hughes products and services, including oilfield chemicals, artificial lift systems and formation evaluation services.

John Meckert

Canrig names vice president services, rentals

John Meckert has assumed the role of vice president of services & rentals of Canrig Drilling Technology. Mr Meckert has been with the Nabors group of business units for more than 16 years, most recently as senior VP of Peak USA. He will be responsible for all of the services that accompany Canrig’s technology, as well as the company’s rental business.

Boots & Coots to buy abrasive jet cutting systems

Boots & Coots has agreed to purchase Halliburton’s external abrasive jet cutting systems, developed in 1991 to assist firefighting crews in Kuwait battle more than 700 fires. It can be easily positioned on a burning well; the system utilizes sand and water to abrade the wellhead or surface equipment, thus allowing the well to flow in a vertical direction, making it possible to extinguish the fire with water. Once the fire is out, the well can then be capped.

Balmoral boosts capacity

Balmoral Offshore Engineering is expanding its buoyancy manufacturing facility and is seeking to recruit upwards of 40 people. It is investing £2 million in a new 30,000-sq-ft manufacturing facility at its Aberdeen HQ. The plant will increase production capacity, especially for marine drilling riser modules. The company also said that it is actively recruiting due to “an increase in orders for drill riser buoyancy and elastomer products.”

Denney joins Scorpion as VP operations

Scorpion Offshore has announced that VP operations George Bruce Brumley will retire in Q4 2009; he will be succeeded by James Harold Denney, who joined the company on 1 September 2009. Mr Denney has over 35 years of experience in the contract drilling business, the majority of which was with Nabors Industries. He has served as the operations manager for Nabors in the North Sea, president of Nabors Alaska and recently as chairman of Nabors Well Services.

VAM looks to Middle East with new acquisition

VAM Drilling has acquired Dubai-based drill pipe supplier DPAL FZCO, formerly owned by the Soconord Group. VAM expects that the acquisition will strengthen its position in the Middle East, where DPAL FZCO offers a large range of drill pipes.

Caledus to market completion solutions in North Sea

Caledus will be the North Sea and Europe representative for Cannon Services’ range of control lines and cable clamps, which are used in the completions phase, particularly in artificial lift. Cannon supplies protection systems for downhole completion control lines and cables.

Halliburton signs 2-year contract with Talisman

Halliburton’s product service line Baroid has been awarded a two-year contract, with multiple extension options, to provide drilling fluids and associated services to Talisman Energy Norge AS. The $229 million contract began in Q3 2009 and encompasses all Talisman-operated fields on the Norwegian Continental Shelf.

InterMoor Brazil facility is ISO 9001:2008 certified

InterMoor do Brasil Serviços Offshore de Instalação, an Acteon company, has received its ISO 9001:2008 certification for its Rio de Janeiro facility. This certifies the company to perform a full range of services, including engineering, design, installation and servicing of mooring equipment and subsea structures.

FMC opens technology center

FMC Technologies is adding a global technology center in Houston to enhance its development of innovative equipment and services. The building will house product management teams and core technology groups, including mechanical and electrical engineers, designers, metallurgists, material scientists, chemists, welding engineers, and other specialists.

New PDC bits, packer system from Baker Hughes

Baker Hughes has introduced its Hughes Christensen Quantec Force line of PDC bits and its Baker Oil Tools MPas packer system. The bit line features new stabilization technology and next-generation cutters that can significantly reduce bit whirl. The bit also uses highly wear-resistant cutters that are selected based on the drilling application. The packer system provides open-hole annular isolation, eliminating many problems associated with cement jobs. Run on production casing or liner string, the packer – plus the uniform production profile created by the BOT EQUALIZER inflow-control devices – enables flow in the annulus to be efficiently managed without the limits or risks associated with no isolation or more complex isolation methods. The packer provides improved time-to-seal control and a wider hole-size range than swelling rubber technology. The packer is electronically activated using the eTrigger controller technology.

GE subsea tree reduces weight and height

GE Oil & Gas has launched the VetcoGray S-Series SVXT subsea tree, which merges horizontal and vertical tree technology, reduces weight by 20% and decreases height. Low-cost installation is enabled through deployment using standard jackups. New features include smaller tree and fisher-friendly wellhead protection structures, as well as an innovative barrier approach that removes the need for a separate tree cap.

Water-based mud used on Fayetteville shales

The Mud Masters Group’s (MMG) Master Clear Fluid and Non-Damaging Reservoir Technology (NDRT) has been used successfully on several Fayetteville shale wells in Arkansas.  Master Clear Fluid is a hybrid water-based drilling mud process that technically rivals the lubrication and inhibitive properties of an oil-based drilling mud system. The NDRT Process uses the Master Clear Fluid to reduce the cost of finding reserves in difficult drilling regions and to reduce overall project costs.

New technology for deepwater platforms

VersaBuoy International’s VersaBuoy Deepwater Platform System comprises four spar-like self-stable hulls supporting the platform topside through articulated redundant pin-in-pin connection. The unique application of the articulated joint between the columns and the topside allows the column rotation relative to the deck and consequently results in a dramatically reduced topside rotation. The connection allows each hull to pitch and roll independently from the topsides. Each hull is sized and ballasted such that it is stable and requires no other constraint or connection. Mooring is by either conventional catenary lines or a taut leg system attached to fairleads located on each hull.

Gas compression driver meets EPA 2011 standards

Cummins has launched the QSL9G gas compression driver, rated 175 hp at 1800 rpm, as its latest offering to meet the US EPA’s New Source Performance Standard (NSPS) 2011 regulations for stationary spark-ignited engines below 500 hp.

Rod guides extend life of rods, tubing

R&M Energy Systems recently launched a new line of rod guides for progressing cavity downhole pumping applications. The New Era Pathfinder High Performance Rod Guides extend the life of the rods and tubing, reduce pressure drop and premature wear from sand, increase production and reduce costs. The spin-thru design allows fluid to easily flow through four distinct channels that are molded directly into the rod guide sleeve. This flow path reduces pressure drop by allowing fluid to flow through the rod guide rather than limiting flow to the space around it. It also reduces the torque that is generated by the mechanical and hydraulic friction of conventional rod guides that are fixed to the rotating rod string.

The supply vessel Bourbon Mistral is fitted with CLEANCUT ISO-pumps that enable finished slurry storage if the injection pump or injection well are unavailable. M-I SWACO’s CLEANCUT system has been used on 900 well sections around the world.

As environmental regulations get more stringent around the world, oil companies, drilling contractors and the service industry are working together to reduce chemical exposure, improve rig safety and reduce the risk of pollution while drilling increasingly complex wells.

When performing top hole drilling with seawater and natural clays in highly regulated areas, the formation cuttings are often discharged directly onto the seabed to minimize impact to the environment, rather than bringing it to surface for collection and transportation back to shore. This will relocate these natural materials and add air pollution, and it may not be the best solution if, for example, vulnerable seabed coral reefs are present.

The technology for removing cuttings from these sensitive areas for disposal in deeper and less vulnerable waters or transportation back to land is available today. Although new high-performance water-base drilling fluid technologies are being developed, technical challenges may require oil- or synthetic-base fluids in some instances. To meet environmental requirements, these fluids must always be used with absolute care.

The CLEANCUT system for pneumatic conveyance of drilled cuttings is a totally enclosed cuttings-handling system that handles all cuttings from water-base and oil-base systems, offshore and onshore, using only clean and pressurized air.  Nearly 900 well sections have been successfully completed with the system around the world, including in North and South America, Europe, Russia, the Mediterranean, Middle East, Africa and Asia Pacific.

The system is totally enclosed and can be automated to reduce personnel onboard. It almost eliminates crane lifts, simplifies the logistics and minimizes deck space requirements. The cuttings are transferred via an overboard hose to the transport vessel using clean, compressed air. A safety coupling can allow a boat to pull away from the rig with no risk of equipment damage or spill if weather conditions get rough. The system will also move cuttings from the collection point to any location on the rig, platform or supply vessel for treatment or storage.

FIELD USE: BRAZIL

Brazil’s environmental legislation requires zero discharge of water-base drilling fluids in shallow waters less than 195 ft (60 m). To enable the development of a gas field offshore Brazil, this cuttings containment system was installed. A vessel that was also equipped with the system was able to sail to deep waters where cuttings discharge is permitted, then discharge the cuttings.

The system on the rigs ensured that drilling could proceed uninterrupted while the containment vessel was away from the drilling site. The Brazilian Institute of Environmental and Renewable Natural Resources (IBAMA) maintained a compliance engineer onboard at all times, and full compliance was achieved. This opened the door to drilling in other restricted areas of Brazil.

The cuttings containment system was also used in a secondary application to receive water-base liquid mud and tank settlements from the rig’s sand traps and to contain residues from the mud pit cleaning. The system also contained interfaces and mud spacers during displacements, proving that it is capable of handling liquid volumes as well as drill cuttings.

FIELD USE: RUSSIA

In another project where the focus was on meeting stringent QHSE goals and mandatory Russian regulatory compliance criteria in an extremely sensitive marine fishing environment, an operator was required to monitor the discharge of all cuttings and drilling waste offshore while drilling an exploration well. The cuttings containment system allowed the operator to drill the well with full compliance of the zero-discharge policy.

The results were zero lost-time incidents, zero spills, zero accidents and 100% compliance with safety initiatives.

AUTOMATION AVAILABLE

The system also offers modular combinations and flexibility, with add-on technology combinations available to make the system automated with full weight control, automatic cleaning, winterization and complete integration with cuttings dryers, offshore thermal treatment and cutting slurrification and injection.

Cuttings conditions and drilling rates vary, and most process systems require continuous feed for optimum operating conditions. They can be buffered with the transport and storage capability that this system offers.

Offshore thermal treatment of cuttings to reduce environmental impact and comply with discharge regulations has a slightly lower process rate than the high ROP drilling dictates. This cutting containment system buffers the drilling operation and temporarily stores cuttings to enable the thermal process to run continuously at its maximum rate, therefore enabling drilling to continue at its maximum rate.

Wet cuttings can be stored prior to the thermal process, and dry cuttings can be stored after treatment, should that be required for transport to other disposal site.

Wet cuttings storage can also be buffered during cuttings reinjection operations if extra capacity is required. There’s also system redundancy for maintenance or shut-down. ISO-pumps enable finished slurry storage if the injection pump or injection well are unavailable for shorter periods.

By using clean, pressurized air to transport cuttings, fluids or other materials, this system allows operators to safely and efficiently handle drilled cuttings and comply with environmental regulations.

CLEANCUT is a mark of M-I, LLC.

Jan Thore Eia is global business line manager within cuttings handling & transportation in M-I SWACO. He has over 24 years of industry experience in technical engineering, management and business development from mainly Scandinavia but also Europe, Caspian, North Africa, the US and South America. He graduated as B.Sc. in Petroleum Engineering from University in Stavanger 1983. He joined M-I in 1985 as a drilling fluids engineer and has been operations manager for both M-I and Swaco in Scandinavia. He holds a Master of Management degree from Oslo Business School 2006.

A crew deploys the BJ Services InjectSafe valve in the North Sea.

BJ Services Company has successfully installed the first InjectSafe chemical injection system with DynaCoil capillary injection strings offshore in two wells in Europe. Installation allowed the company to inject foaming agent directly downhole through the capillary string without compromising the integrity of the surface-controlled subsurface safety valve (SCSSV).

The foaming agent, which foams condensate produced from the well, prevents liquid from accumulating in the well and enables production to flow continuously, resulting in an increase in overall gas production rates.

BJ carried out the project in the North Sea with operational support from its base in Aberdeen.

The chemical injection system allows wells to retain SCSSV integrity and operability by preserving the existing control line function, while allowing injection of fluids directly to the wellbore below the SCSSV. The system is run in conjunction with capillary injection tubing using specially engineered capillary tubing equipment. This equipment is designed specifically for running small-bore tubing into wells and features a small wellsite footprint to reduce impact upon other platform operations.

The method of installing the system is usually straightforward. The existing tubing-retrievable SCSSV is locked open and the chemical injection system, featuring the FlowSafe SCSSV and capillary string assembly that is long enough to reach the predetermined depth, is run in the well on wireline, then set and locked in place.

A stinger attached to the upper capillary string is then run into the well, using a special injector head, until the stinger locates in the downhole receptacle within the SCSSV system. This establishes fluidic communication from the surface, around the safety valve, and to the bottom of the well, enabling chemical or foamer injection to take place.

Integrity, through the capillary string, is maintained by four check valves located within the system. These prevent any backflow from the well being able to reach surface through the capillary string. Two are located in a bottomhole assembly, one within the SCSSV body and one inside the stinger.

The recent installation is the first time that BJ Services has employed this technology offshore in Europe.

“By installing this system offshore, we can economically treat wells prone to production-related issues such as liquid loading, salting, waxing, scaling and hydrate problems,” said John Anderson, region vice president – Europe & West Africa for BJ. “These conditions can now be treated without pulling the tubing to install a capillary string, which would be a more expensive and time-consuming option,” he added.

The system allows effective downhole treatments by enabling the installation of small-diameter capillary strings within the production tubing to apply specialty treatments to enhance production without compromising the capability of the SCSSV. The capillary strings can be run to depths of 22,000 ft (7,000 m).

RECORD SET ON US LAND 2-SECTION LATERAL

Baker Hughes recently used the INTEQ 4 ¾-in. X-treme motor technology and the CoPilot service to drill the fastest two-section lateral to date in 6.42 days for a Williston Basin operator. They then deployed the first Baker Oil Tools Frac-Point extended stage system, enabling the operator to frac the well with 18 stages using new frac sleeve technology. Real-time data helped to optimize the drilling parameters to realize the full potential of the motor technology. The additional bending moment information contributed to improve wellbore quality, eliminating unnecessary slides, reducing the number of localized doglegs, and allowing the 18-stage completion to be run.

Baker Hughes also recently successfully installed the first BOT 9 ^5/8-in. “Float-In” liner hanger on Sakhalin Island, Russia. This was a critical milestone in a challenging project due to the significant extended-reach well profile. The liner had a length of 2,911 m (9,587 ft) and was installed at a total depth of 6,603 m (21,663 ft) with 83° inclination.

TECHNOLOGY MAPPING UNDER DEVELOPMENT

A technology mapping capability is being developed by the Industry Technology Facilitator and OTM Consulting. It will allow users to understand how their technology needs fit in with the global “landscape” of existing, field-trial-ready and emerging technologies. The companies hope this will help to accelerate the uptake of new technology and enable greater collaboration and end user input to the development of new technology, as well as allow R&D budgets to be targeted more effectively. The technology mapping function will be integrated into a knowledge base called TechnologyTradingPost.

DOE AIMS TO TURN OILFIELD CO-PRODUCED WATER INTO ENERGY SOURCE

A US Department of Energy (DOE) collaboration is trying to generate electricity from a geothermal source stemming from oilfield operations. The Office of Fossil Energy (FE) and the Office of Energy Efficiency and Renewable Energy’s (EERE) Geothermal Technologies Program will merge and leverage research capabilities to demonstrate low-temperature geothermal electric power generation systems using co-produced water from oilfield operations at FE’s Rocky Mountain Oilfield Testing Center (RMOTC).

EERE is providing funding for the purchase of a geothermal electricity producing unit. RMOTC will serve as a testing facility for geothermal technologies. The system will turn otherwise discarded water into an energy resource. With an estimated 10 barrels of hot water co-produced along with each barrel of oil in the United States, there is significant resource potential for this technology. The electricity produced will be used to power field production equipment.

Operational and performance data will be collected and made available to industry and the public highlighting the potential of geothermal renewable energy from co-produced water.

HIGH ARTIC ENERGY SERVICES ACHIEVES A MILLION MANHOURS WORKED WITHOUT LTI

Rig locations in Papua New Guinea are often fly-in locations and very isolated. There are no roads so rig moves are conducted by helicopters.

On 30 September, High Arctic Energy Services Papua New Guinea (PNG) passed one million manhours without a lost-time incident. During this time, the company has:

• Driven in excess of 840,000 km without serious vehicle incidents.
• Conducted 36 rig moves, including separate Leap Frog and main rig package moves. Three of the rig moves were fly moves.
• Skidded the rigs three times to the next well on the same location.  A number of other skidding has taken place to move the rig off the well to rig down.
• Drilled nearly 23,000 m of hole.
• Submitted 21,161 stop cards (13,525 safe, 7,636 unsafe).
• Submitted 4,745 hazard cards (4,736, or 99.8%, have been closed out).

ACOUSTIC OPTICAL FIBRE SYSTEM INSTALLED IN CBM WELL

Fibre optic sensing systems company Fotech Solutions installed the world’s first dedicated downhole distributed acoustic optical fibre system using the company’s new Helios monitoring solution in August 2009. The distributed acoustic monitoring system was installed in a coal-bed methane well in Scotland for Composite Energy. The system can be deployed in a range of applications, including reservoir surveillance, production monitoring, integrity assurance, flowline movement, flow assurance and leak detection.

NEW SERVICE TO ALLOW REAL-TIME FRACTURE CONTROL

Baker Hughes Inc and BJ Services Company have launched the IntelliFrac service to enable operators to monitor fracture dimensions during stimulation treatments and to allow real-time control of fracture operations. Fracturing and production enhancement services will be provided by BJ and advanced microseismic services by Baker Hughes.

During hydraulic fracturing operations, the new service monitors and measures the microseismic events that indicate key fracture properties, including azimuth, height, length, volume and complexity of the induced fractures. By understanding hydraulic fracture propagation, operators can make better on-location treatment management decisions and in turn reduce well completion and stimulation risk and uncertainty. Once the microseismic data set has been gathered and processed, operators can use the data to optimize field development plans and potentially reduce the number of wellbores required to develop the field.

ABRASIVE CUTTING TOOL USED SUCCESSFULLY IN GOM

InterMoor, an Acteon company, has completed its sixth job in the Gulf of Mexico using the Scimitar Abrasive Cutting Tool, where the abrasive is introduced at the cutting head versus a slurry mix (abrasive mixed at the high-pressure pump). The tool uses ultra-high pressure water to move abrasive at transonic speeds to cut virtually any type of material. It was adapted from a pneumatic tool to a hydraulic tool that centralizes inside of the pile or caisson. The company also recently sold its 100th Permanent Chain Chase (PCC), which assists with installation and recovery of anchors from the seabed. It has a lifting capacity of 150 tons.

Anadarko Petroleum has announced another successful appraisal well in the West Cape Three Points Block offshore Ghana. The Mahogany-4 well, the eastern-most appraisal of the Jubilee field, encountered more than 140 net ft of predominately oil pay in high-quality, stacked reservoir sands. The well is located approximately 5 miles east of the original Mahogany-1 discovery well.

The well was drilled to a total depth of about 12,000 ft in approximately 3,540 ft of water by the Atwood Hunter semisubmersible. Once the rig completes operations at Mahogany-4, it will move to drill a development well in the Jubilee field, followed by appraisal wells to delineate the Odum and Tweneboa discoveries.

The partnership also recently spud the Mahogany Deep-2 well in the West Cape Three Points Block. This well is an appraisal of the Mahogany Deep discovery announced earlier in 2009.

In Cote d’Ivoire, the company announced that the South Grand Lahou exploration well in block CI-105 was drilled to a total depth of approximately 14,900 ft in about 6,100 ft of water. Although the well did not encounter hydrocarbons, it provided data that the company plans to incorporate into models as it evaluates its 2010 program.

The company now intends to mobilize the Belford Dolphin drillship to Mozambique to begin its drilling program obligation with the Windjammer prospect. Windjammer will be the first deepwater exploration well to be drilled offshore Mozambique.

MAERSK DISCOVERER DELIVERED BY KEPPEL

The DSS series rigs can drill down 30,000 ft and operate in water depths up to 10,000 ft. They’re also dynamically positioned units.

Keppel FELS delivered the Maersk Discoverer, the second of three DSS 21 deepwater rigs, to Maersk Drilling on 22 August. The rig has been contracted by Woodside Energy for drilling operations in Australia for three years.

Claus V Hemmingsen, Maersk Drilling CEO and 2009 IADC chairman, said, “Maersk Discoverer, our second DSS 21 rig, is another outstanding example of the winning collaboration between Maersk Drilling and Keppel FELS.

“Optimised for field development work, the new-generation DSS 21 series is derived from the experiences gained from our highly successful DSS 20 Maersk Explorer semisubmersible built in 2003. These deepwater units are among the most technically advanced in the world, and we are confident that they will position Maersk Drilling as the foremost provider of robust offshore solutions in the industry.”

OIL DISCOVERY MADE AT TEBE OFFSHORE ANGOLA

Sonangol and BP recently announced the Tebe oil discovery in ultra-deepwater Block 31, offshore Angola. This is the 19th discovery made by BP in Block 31 and is located in the southern portion of Block 31 some 350 km northwest of Luanda and about 12 km southeast of the Hebe discovery. Tebe was drilled in a water depth of 1,752 m and reached a total depth of 3,325 m below sea level. The well results confirmed the capacity of the reservoir to flow in excess of 5,000 bbl/day under production conditions.

XTREME COIL RIGS LAND CONTRACTS IN MEXICO

Xtreme Coil Drilling Corp has signed new 18-month contracts for eight Coil Over Top Drive drilling rigs located in Mexico. The company now has all 10 rigs in Mexico contracted into the 2011 fiscal year. The rigs will continue to operate in the Chicontepec oil development project near Poza Rica in the state of Veracruz.

ENSCO 8501 BEGINS OPERATIONS IN GOM

Ensco International’s ENSCO 8501, the second of seven new ultra-deepwater semisubmersibles in the ENSCO 8500 series, commenced operations in the Gulf of Mexico on 8 October under a 3 ½-year contract with Nexen and Noble Energy.

As planned, commencement of operations began by spudding the initial well, followed by a short period of final acceptance testing before recommencing operations.

CONSTRUCTION RESTARTS ON 4TH ROWAN EXL JACKUP IN TEXAS

Rowan Companies announced that it will resume construction of its fourth EXL class jackup rig at the Keppel AmFELS shipyard in Brownsville, Texas, with delivery expected in the first quarter of 2012. Construction had been suspended in early 2009 due to liquidity concerns and a weakening jackup drilling market.

“We believe the recovery outlook in global oil demand and a potential re-tightening of rig markets will have gained momentum by the time this rig is delivered in 2012,” said Matt Ralls, Rowan president and CEO. The first three EXL rigs have deliveries scheduled for the second, third and fourth quarters of 2010.

PV DRILLING JACKUPS NAMED SIMULTANEOUSLY

PV Drilling plans to build up a fleet of 11 rigs to meet demand in the Vietnamese market.

Two identical jackups, PV Drilling II and PV Drilling III, were named by Keppel FELS and PetroVietnam Drilling & Well Services Corp (PV Drilling) in early September.

It is estimated that there will be some 900 exploration wells drilled in Vietnam over the next 15 years. To meet the tight exploration schedule, PV Drilling intends to make capital investments of around US$1.7 billion from now until 2025 to build and operate an 11-strong fleet of offshore and onshore rigs.

Mr Do Van Khanh, CEO of PV Drilling and chairman of PVD Invest, said, ”We want to position ourselves to capture Vietnam’s growing market for oil and gas services with the support of a strong and reliable shipyard that can deliver projects punctually, on budget and without incidents.”

The KFELS B Class rigs can operate in water depths up to 400 ft with a drilling depth of 30,000 ft. PV Drilling III has been further enhanced with features like engines that meet more stringent emission standards and lower spud can bearing pressure for operation in areas with soft soil conditions.

Click below for a DC exclusive video interview with Mr Khanh.

PETROBRAS 10000 BEGINS OPERATIONS IN ANGOLA

Transocean’s newbuild ultra-deepwater drillship Petrobras 10000 has commenced operations in Angola for a subsidiary of Petrobras under a 10-year drilling contract. Transocean has an agreement with the P&M Drilling International B.V. joint venture of Petrobras and Mitsui to acquire the rig under a 20-year capital lease contract.

The rig features patented dual-activity drilling technology, allowing for parallel drilling operations. Other features include expanded completions capabilities, a variable deck-load of more than 20,000 metric tons and the capability of development and exploration drilling in greater than 10,000 ft of water.

Separately, the company’s ultra-deepwater semisubmersible Deepwater Horizon has been awarded a three-year contract extension by a subsidiary of BP for operations in the US Gulf of Mexico commencing September 2010. The rig is capable of operating in water depths up to 10,000 ft, and it recently set the world record for the deepest oil and gas well at 35,050 ft total vertical depth, drilled for BP.

SEADRILL TO MOBILIZE JACKUP OFFSHORE SUDAN

Seadrill has been awarded a two-well contract by Red Sea Petroleum Operating Company Ltd (RSPOC) for the jackup West Prospero. The assignment is for operations offshore Sudan, with mobilization scheduled for December 2009. The drilling assignment is expected to take some six months, and the estimated contract value is approximately US$49.9 million. The rig, which is currently idle in Indonesia, will be upgraded with high-pressure, high-temperature capabilities prior to moving to Sudan.

NEW STIMULATION VESSEL SET TO WORK IN GOM

The Blue Dolphin can provide 80 bbl/min blending rates for ultra-deepwater fracturing/stimulation projects.

BJ Services Company is launching Blue Dolphin, a high-performance stimulation vessel for wells in the Lower Tertiary and other Gulf of Mexico formations. It’s been designed to provide 20,000 psi working pressure via multiple Coflexip reeled flexible umbilical lines. With accommodations for up to 45 crew members, the vessel can perform large-volume, high-pressure stimulation operations with minimal downtime for multizone or multiwell operations. It features a DP-2 system and will receive well stimulation/offshore support vessel class notation, certified by ABS. It comes equipped with eight 3,000-brake hp Gorilla fracturing units and storage capacity for 2.75 million lb of proppant.

Gert-Jan Windhorst

Two longtime IADC champions received Exemplary Service Awards at the 2009 Drilling HSE Europe Conference & Exhibition in Amsterdam on 23 September. Gert-Jan Windhorst, Noble Drilling (Netherlands) BV, and Harald Bratthammar, Seadrill, were recognized for their outstanding contributions to the industry, with emphasis on advancing HSE and training.

Mr Windhorst, manager-HSE&Q Europe for Noble, initiated the IADC Northwest European HSE Case development project, and Mr Bratthammar, Seadrill’s QA director, participated in the effort. The IRF award-winning HSE Case Guidelines have gained broad regulatory acceptance, from Europe to the Caribbean to Australia and other regions.

Harald Bratthammar

Both men have long served on the IADC European Operations Forum and were co-developers of the IADC Offshore Competency Training Programme. Both serve on the IADC Environmental Policy Advisory Panel and are long-time and continuing members of the programme committee for the IADC Drilling HSE Europe conference.

Mr Windhorst began his career in merchant shipping and later joined the HSEQ department of Neddrill, a legacy Noble company. In 1998, he was appointed HSEQ manager for Europe. During this time, Mr Windhorst worked on Noble’s Super EVA design, a novel concept for a new generation of semisubmersibles. The EVAs were the first rigs certified under the ISO 14001 environmental standard.

Mr Bratthammar is a 1981 graduate of Rogaland Regional University in Stavanger, Norway, where he earned a degree in petroleum technology. That year, he joined the Norwegian Petroleum Directorate, now the Petroleum Safety Authority Norway, as a drilling engineer. In 1986, he joined Polar Frontier Drilling AS as safety and QA manager, and in 1988, he moved to Conoco Norway as regulatory supervisor for the Heidrun Project.

He joined Smedvig Offshore AS in 1996 as QA manager and was named manager of the Q&HSE department in 1998. With Seadrill’s March 2006 acquisition, Mr Bratthammar became part of corporate management, serving as vice president-Q&HSE. The position was recently split, and Mr Bratthammar obtained his current title.

JENS HOFFMARK, MAERSK DRILLING USA VP PRESENTED WITH GIFT BY IADC PRESIDENT DR LEE HUNT

IADC president Dr Lee Hunt (right) presents a commemorative gift to Jens Hoffmark, Maersk Drilling USA vice president business development, at a meeting of the IADC Ethics & Corporate Compliance (E&CC) Committee on 29 September in Houston. Mr Hoffmark is a longtime and avid supporter of various IADC initiatives and has been active with the E&CC Committee since its inception in September 2007.

WELLCAP FACILITATOR CERTIFICATION COURSE

WellCAP instructors are now eligible to participate in the Facilitator Certification course originally reserved for WellCAP Plus program instructors. This will allow eligible instructors to become a WellCAP/WellCAP Plus certified facilitators.

To become a certified facilitator, WellCAP instructors must complete and pass the four-day Facilitator Certification course. It is intended to help instructors develop the essential skills for establishing an interactive learning environment and assisting students to immediately apply the skills learned. Facilitation skills to be taught include effective communication, presentation and questioning skills; how to introduce, manage and process classroom exercises; and how to synthesize learnings.

WellCAP/WellCAP Plus certified facilitator certificates will be issued to instructors who obtain an 80% or better total score on daily exams and the final skills check exercise. Additionally, all WellCAP instructors who attend the Facilitator Certification course will receive 40 hours of credit to satisfy the continuing education requirement for maintaining WellCAP instructor approval.

IADC OFFERS GUIDE TO COMMITTEE CHAIRS

IADC has published a brief guide to assist IADC committee leaders with the operation of various committees. The guide includes tips on IADC’s anti-trust policy and guidelines, preparing for meetings, conducting meetings and recording meeting minutes. The guide can be found in the Committees menu listing on the IADC website. For more information, contact committee coordinator Holly Shock at +1/713-292-1945 or holly.shock@iadc.org.

EUROPEAN OPERATIONS FORUM HOLDS MEETING

Beate Raabe, director of EU affairs for the International Association of Oil & Gas Producers (OGP), was the featured speaker at the September meeting of the IADC European Operations Forum in Amsterdam in September. Topics discussed included contractor HSE and operations issues and the IADC Offshore Competency Programme.