By Jim McKay, Allen Pere, BP; Clayton Simmons, Mike Doty, National Oilwell Varco; Tony Hogg, Ensco; Gavin Starling, Rock Oilfield Group

Figure 1: Traditional MUX BOP control system diagnostics are geared toward maintenance and troubleshooting more than operational decision-making. A BOP dashboard concept is being studied that would improve communications among operations personnel, contractors and the OEM to assess BOP health issues.

As every motorist knows, a vehicle’s dashboard is an important interface that alerts the driver of real-time changes regarding certain car engine “health” metrics and alerts the driver that the engine may need to be serviced. While not a diagnostic tool in and of itself, the dashboard serves to alert the driver that a performance or health issue may exist.

Blowout preventer (BOP) equipment is designed to secure the well, and a BOP’s health is critical to ensuring that it works as designed. A real-time BOP dashboard can improve communication between operations personnel, rig contractor subsea engineers and the original equipment manufacturer (OEM) to assess potential BOP health issues.

This article describes a development process for a BOP dashboard and discusses the potential benefits, challenges and lessons learned associated with implementing a BOP monitoring system.

Traditional multiplex (MUX) BOP control system diagnostics (Figure 1) are designed by OEMs for use by personnel proficient in BOP control systems, such as a rig contractor’s subsea engineer. Control system diagnostics are generally geared toward maintenance and troubleshooting system problems more than operational decision-making.

Traditionally, the BOP diagnostic data is solely available at the rig-based engineering work station (EWS), also known as the event logger. Historically BOP data is not exchanged to shore from the offshore event logger. The industry could benefit from having BOP control system integrity or BOP health presented in a manner that allows operations people (offshore and onshore) to participate in communication with BOP experts to assess any risk associated with the BOP and the BOP control system.

The Concept

The BOP dashboard (Figure 2) aims to simplify complex BOP diagnostics in an easy-to-understand format that facilitates a joint assessment of the issue. In early 2011, BP, Ensco and National Oilwell Varco (NOV) collaborated on a project to consider preliminary development of a BOP dashboard that takes existing alarms, analog data and events from the BOP EWS and translates them into a high-level “traffic light” status. The traffic light logic is based on levels of system redundancy that allow the user to understand when critical functions are impaired.

The first phase of the project focuses on the electrical components of the control system, with further extension to the hydraulic components in the subsequent phases of the project. Although the initial dashboard would rely solely on the NOV eHawk platform, the end product could be a BOP monitoring dashboard incorporated into a mud-logging network.

When integrated with the common mud-logging database, the BOP data could be interconnected with other real-time well construction systems, such as digital BOP pressure-testing technology.  If a BOP health issue should arise, the OEM web platform can provide additional layers of detail beyond the dashboard.

These additional layers should provide the user the same screens that are already available in the offshore BOP diagnostic system. Such a system can also be designed to allow near real-time archiving of raw BOP data on an onshore computer and can produce a BOP health report.

Although this system is not designed for or intended to be used for continuous monitoring, the end user can view the dashboard at any time, and reports summarizing alarm and event information can be sent automatically to select users.

Thus, this system could be a useful tool for well-site leaders (including the company man), offshore installation managers or shore-based operations teams. For example, operations teams could use this system to review applicable BOP health attributes prior to each daily rig call.

Software, Hardware Development and Installation

In this project, the EWS must be configured to allow for data export to the eHawk server. Although historically SQL data was used, NOV determined that the interoperability standard for automation (OPC) provided advantages for configuration. OPC has the ability to queue data and push an initial state for BOP positions and outstanding alarms. This is important when data transfer is lost or upon initial installation of the BOP monitoring system. OPC simplified the configuration by not requiring manual entry of outstanding alarms and initial positions into the eHawk database.

Figure 3 shows a simplified system diagram of the connection between the EWS, the eHawk server and the relevant Sitecomm server.

For the installation, NOV had to update the OEM drawings to show the new connection from the EWS and the eHawk server. The BOP control system had to be recertified from American Bureau of Shipping to reflect this change.

‘Traffic Light’ Development

The OEM holds the unique system knowledge required for traffic light logic development. For example, the OEM can provide guidance on the meaning of alarms and system redundancy. The operator and rig contractor can define the levels of risk that would be associated with each level of traffic light.

Figure 2: Several companies have looked at developing a BOP dashboard that aims to simplify complex BOP diagnostics. The dashboard would take existing alarms, analog data and events from the BOP engineering work station and translate them into high-level traffic light status. The traffic light logic is based on levels of system redundancy that allow the user to understand when critical functions are impaired.

Originally three automated tiers of colors were envisioned to provide the health status of the BOP. “Red” status would mean no functionality, “yellow” status would mean functional but no redundancy, and “green” status would be fully functional and with redundancy.

As the BOP owner, the rig contractor may wish to retain the ability to manually change the traffic light severity due to the potential for false-positive or false-negative traffic lights. For example, it is possible that due to interdependencies between alarms, a minor alarm could also trigger a more severe alarm. In those instances, the dashboard traffic lights can be manually changed from a more severe status to a less severe status. The manual override can be done for a specific alarm, and the related traffic lights will be identified by an “F” indicating the traffic light was forced to a more or less severe status. To manually force or clear any alarm, the user is forced to enter a description that details the reason for the force.

In addition to a management of change process, this information allows for future review and oversight. The forcing of alarms, not traffic lights, allows subsequent alarms to change a traffic light status with an “F” to an increased severity level.

In addition, the user can scroll over a traffic light to view the outstanding alarms and to identify those alarms that were forced.

Different parts of the control system may have different levels of redundancy. In this project, at a minimum, redundancy for a specific BOP function is required for the traffic light to be green. An example of redundancy is the use of dual pods (yellow and blue). An example of dual redundancy would be communications to the pods. Each pod receives redundant communications, and the pods themselves are redundant; hence each pod receives a spare communication link to the surface control system.

For the BOP system, if the component is shared by the pod, then redundancy is required. If the component is specific to the pod, then redundancy is not required.

The current traffic light logic development used in this project omitted alarms related to the hydraulic system data (Phase II) or minor alarms (e.g., stuck push button alarms).

Dashboard GUI Development

When developing the graphical user interface (GUI) for the dashboard, the target users were assumed to include both experienced subsea engineers and those on an operations team with only a rudimentary knowledge of the BOP control system.

Starting in the top left of the dashboard and working to the bottom right, the following design requirements were built in the dashboard for this project:

• Top left – The last test date for auditing purposes will be manually entered and recorded.

• Upper left – Leaks and hydraulic issues will be detected with logic (Phase II development) and reported with a traffic light status.

• Lower left – Emergency systems status will be based on the solenoid valve health.

• Bottom left – Event log data will capture raw commands in a table with volumes, times for the activation and the location of the command.

• Bottom left – Outstanding alarms will capture raw alarm data, the time of the first alarm, the number of alarms in the last 24 hours, time of the last alarm acknowledgement and location of the last alarm acknowledgement.

• Bottom left – MUX fiber will report multiplex fiber health based on existing alarms.

• Bottom left – Surface alarms and subsea alarms will report all alarms and sort them based on the location of the equipment. This will allow the user to understand if the BOP stack should be pulled in the event of a yellow health status on a specific BOP function. These are envisioned as all-inclusive alarm traffic lights regardless of redundancy or alarm severity. This will also allow the user to understand if a minor alarm has been triggered.

• Middle left – Read back pressures will report the analog pressure for each specific function closing pressure. For example, this will allow the user to understand if the closing pressure was increased to obtain a seal.

• Middle – BOP function health separated by yellow and blue pods. Each major BOP function will have a displayed traffic light health indicator for each pod. The active pod will be indicated by a traffic light that is 50% larger than the non-active pod.

• Middle – BOP positions will be viewable by colored circles and blocks that animate physical position of the rams, annulars and subsea BOP valves.

• Right – Chronology log will display the positions and the overall health of the system over a 24-hr period. If the user is not constantly monitoring the BOP dashboard, they can look back at a high level to understand if the BOP was functioned or if there was a BOP health issue.

Figure 3: The engineering work station, or event logger, had to be configured to allow for data export to the eHawk server. This figure shows a simplified system diagram of the connection between the EWS, the eHawk server and the relevant Sitecomm server.

Monitoring and Decision-Making

The real-time BOP dashboard will only be used as a communication tool by facilitating conversation between operations teams on BOP health issues. The primary diagnostic system will remain the original rig-based OEM EWS. The workflow process (Figure 4) requires that the EWS be used to confirm the dashboard before making any decisions.

One item that the project considered in the workflow process was the need to avoid uncontrolled distribution of data to individuals that may not fully understand the significance of various alarms. Not all alarms are equally important, and this distinction must be addressed when working with the dashboard.

Part of the pilot intent is to develop a decision tree protocol (Figure 5) where operations teams can make standard operation decisions. This will help eliminate the potential for subjective BOP health resolutions. Ideally, all BOP health scenarios would be mapped with a decision tree; however, it is more realistic to assume that some alarms will not fully reflect the true health of the BOP.

Once an alarm is triggered, the rig crew will need to confirm the BOP health issue by troubleshooting the issue. For example, if a MUX fiber signal triggers an alarm indicating fiber degradation, the crew will be able to perform a decibel loss test to confirm the issue.

For this version of the console, the decision protocol was set at a level to allow operations teams to determine the health status and remedial action. By allowing the user to manually change the health rating, the user can override the automated traffic light logic.

In time, as the diagnostic system and traffic light logic is accepted by the operations teams, the ability to manually override the BOP health status may be eliminated. For example, a future operations decision tree could have a defined scenario that requires the BOP to be pulled if a blind shear ram solenoid valve becomes inoperable.

Pilot Program

The milestones for the pilot program will be:

1. Sending alarm and event data back to shore.

2. Developing a working dashboard.

3. Potentially using the dashboard for decision-making and learning from that experience.

As stated previously, Phase I of the technology will focus strictly on the MUX electrical system; however, Phase II will include hydraulic diagnostics.

Digital security processes and hardware are long lead items that require careful planning for the first installation. An installation plan cannot be finalized until rig surveys are complete. The monitoring system can only be installed between wells when the BOP is on surface.

The major challenge and learning in this pilot program will be when the rig contractor and operator disagree on the BOP health status or the proposed remedial action of a BOP health issue. As this technology is adopted, it is anticipated that these situations will be addressed through agreed upon policies and procedures or decision trees.

Figure 4: The primary BOP diagnostic system will remain the rig-based OEM EWS, with the real-time BOP dashboard used as a communication tool for facilitating conversations between operations teams on BOP health issues. The workflow process requires that the EWS be used to confirm the dashboard before making any decisions.

The Way Forward

The hydraulic system will be addressed in Phase II by creating high-level traffic lights for leak detection and pressure vessel health. Leak detection methods include mix pump cycles, hydraulic fluid usage and flow measurements. In addition, each BOP function uses a specific volume that can be measured and compared with a previous baseline for leak detection.

Advancing the diagnostics with better sensors or algorithms will further develop the BOP dashboard. Ram position sensors, tool joint position sensors, BOP cameras and additional BOP wellbore pressures are examples of potential sensor upgrades.

The BOP dashboard data can eventually be integrated with the digital BOP pressure testing. This will allow the rams that were functioned to be identified for the pressure-testing data. Numerous key performance indicators (KPI’s) also can be calculated as more real-time data is gathered. For example, the number of cycles on a solenoid valve or the frequency of successful annular pressure tests can be captured.

These KPI’s and other collected data might eventually be shared amongst the industry through existing organizations, such as Offshore Reliability Data. This collective industry data can provide more robust fault tree analysis that could potentially provide real-time probability of “failure on demand” when certain functionality is lost.

Drilling Contractor Perspective

As the “big crew change” begins, more and more of the highly experienced subsea engineers are transferring to shore-based, or auditor-type, positions, challenging the industry to develop competent replacements. A well setup dashboard, supported by an agreed detailed decision tree, will allow these shore-based experts to better assist the rig-based subsea engineers to diagnose any problems, to discuss the issues with their client counterparts and to decide the most sensible path forward.

The BOP dashboard will not reduce the need for development and training of the rig-based subsea engineers. The BOP dashboard can only report the “health” of the system. It cannot, by itself, do anything to maintain its condition; this has to come from the allocation of sufficient time and resources, between each well, to properly maintain and test all of the subsystems.

This equipment can only be maintained and operated to the standards to which it was designed and manufactured (API 16D 2nd Ed.), regardless of the ease of monitoring afforded by the BOP dashboard. Improvements in BOP and BOP control system designs by the OEMs will be important factors in realizing future reliability enhancements.

Figure 5: A possible operations decision tree for the pilot shows where operations teams can make standard operational decisions. This would eliminate the potential for subjective BOP health resolutions. Ideally, all BOP health scenarios would be mapped with a decision tree.

OEM Perspective

Transferring the most up-to-date and accurate information back to the OEM allows the company to design more reliable equipment, as well as provide appropriate support to the customer. In the past, this was done over the phone, by email or required travel to the rig. Using this tool, OEMs can look at BOP information in near real time and better assist in decisions regarding the safe and proper operation of the equipment.

Summary

A BOP dashboard that simplifies existing diagnostics and allows for remote monitoring of the subsea BOP control system will improve communication of BOP health. Future deployments of the BOP dashboard could serve as a common platform across rig fleets that allow standardization of BOP diagnostic data and aids in operational decision making.

This article is based on IADC/SPE 151182, “Blowout Preventer (BOP) Health Monitoring,” presented at the 2012 IADC/SPE Drilling Conference and Exhibition, San Diego, Calif., 6–8 March 2012.

We pride ourselves on innovation, but are actually laggards at technology adoption.

“The oil and gas industry tends to have a technology adoption cycle of roughly 30 years from concept to 50% market penetration,” remarked Dustin Torkay, Seadrill, IADC Advanced Rig Technology (ART) Committee vice chairman-Future Technology, adding that this is an eight-year process in the medical industry. Mr Torkay is the driving force behind our 12 June ART Workshop on technology adoption. The afternoon workshop will convene in Barcelona the day before IADC World Drilling 2012.

Tom Bates, Lime Rock Partners, an ART workshop panelist, agrees that the pace of technology adoption is “painfully slow.” Mr Bates should know. His long career prior to joining investment firm Lime Rock as a managing director began with Shell and includes leadership positions at Baker Hughes, Weatherford Enterra and Schlumberger.

“There is almost an order of magnitude difference from other industries,” he said. “It’s a bit of a conundrum, (because) overall, our industry is not risk averse.”

Stagnation Generation

One case in point is stagnation in directional MWD, which, according to sponsors of a new Drilling Engineering Association joint industry project (JIP), has not appreciably advanced in a generation.

Now, before MWD partisans rouse to churn out indignant emails championing their companies’ achievements, let me stress that MWD overall has seen many advances. But, according to the DEA JIP sponsors, the process for directional MWD has barely budged in 30 years.

“The perception is that it’s good enough, because we are able to get to the production target,” said Robert Estes, Baker Hughes, which, along with ConocoPhillips and Bench Tree Group, are current sponsors.

The need for more precise directional MWD is pressing, Mr Estes says. A next-generation MWD tool drilling a relief well could reduce time to intersection and enhance accuracy. For infill drilling amid a spider’s web of directional wells, avoiding collision through pinpoint placement might prevent a blowout. For steam-assisted gravity-drainage wells, more precision can maximize production by optimizing well placement.

The organizers are seeking another seven or so JIP participants, at about $30,000 each. (Click here for more on the JIP.)

Dragging Innovation

The question remains. Why does innovation drag? ART workshop participant Jan Brakel, manager for wells R&D with Shell, suspects that with activity booming, the status quo suits most. “Is there a need to innovate?” he asks, though he himself is a strong proponent of change.

He points out that, rig newbuilding notwithstanding, a plethora of ancient equipment still keeps turning to the right.

“In general, as a drilling industry we have a significant catch-up opportunity in terms of technology,” Mr Brakel said.

Business Units Limit Vision

Mr Bates suggests that innovation began to flag when major oil companies switched to the business unit model.

“Business units are great for giving objectives and giving senior manager accountability for results,” he said.

On the other hand, a business-unit leader’s focus on that narrow bottom line is hardly an incentive to try something new, expensive and with potentially large downside risk.

Independents harbor a more entrepreneurial spirit, Mr Bates noted.

“It wasn’t a supermajor that developed the Barnett, with 25 frac jobs and 15,000-ft laterals,” he pointed out.

A corollary of narrowed vision is a dearth of test sites, he added.

“One of the frustrating things for me,” Mr Bates said, “is the inability to get products in the field and tested. That is a real barrier to progress.”

Mr Bates urges industry to develop a cooperative means to test promising technologies without jeopardizing wells, thereby helping to move technology forward.

“At the end of the day, technology works.”

Mike Killalea can be reached via email at mike.killalea@iadc.org.

Figure 1: The Kirchweidach wells have the longest open-hole sections for geothermal wells, from 1,241 meters to 1,378 meters.

Underbalanced runs prevent mud losses and reservoir damage, allow well to hit main fault

By Essam Sammat, Stephen O’Shea, Gareth Innes, Weatherford UK; Julio Kemenyfy, Darko Piscevic, GEOenergie Bayern

Wells in the Kirchweidach geothermal project in Bavaria, Germany, and other offset wells in the area have faced problems such as severe mud losses and differential sticking in the reservoir formation. However, control pressure drilling (CPD) was successfully applied to address those challenges.

The project’s objective was to erect a power plant that would produce 6 to 8 MW of electricity and supply the local town and industries with district heating using thermal energy. Two wells were planned targeting natural fractures in the Malm formation (Jurassic carbonate), including one producer and one injector. This would allow more than 90% of the produced water to be returned to the reservoir, in time making the project sustainable.

The first geothermal well was drilled using CPD equipment in the reservoir section from the beginning. The underbalanced borehole pressure was achieved by pumping various rates of nitrogen and fresh water with polymers, which can significantly reduce nonproductive time and formation damage. For the second well, CPD equipment was used only after mud losses appeared.

The Malm formation is an underpressured aquifer that is often karstified, which at times resulted in severe or total fluid losses in the wells crossing it. In Kirchweidach, the top of Malm is at around 3,450 meters TVD, 400-meters thick and 130°C. As fluid losses during drilling are an indicator of success for the project, a procedure was implemented to allow drilling under these conditions to reach all targets while keeping the reservoir as clean as possible.

The Kirchweidach wells have the longest open-hole sections for geothermal wells, with GT 1 at 1,276 meters, GT 2 at 1,241 meters and GT 2a at 1,378 meters. They are also the only horizontal wells drilled in this formation. At the top of Malm, the separation between GT 1 and GT 2a is 1,600 meters. Figure 1 shows the typical well design, and Figure 2 shows the structural placement of the wells.

Controlled Pressure Drilling

Controlled pressure drilling uses a closed and pressured wellbore instead of drilling with the hole “open” to the atmosphere. A rotating control device (RCD) closes the well at surface, allowing for more precise control of the pressure profile. The RCD directs the flow of cuttings brought up by the aerated/nitrified fluid from the rig to the geothermal separator.

To do this, the flowline from wellhead to separator connects to a drilling spool below the RCD. This facility also provides the option of flowing cold water over the top of the well to stay within RCD rubber element temperature specifications if necessary.

The rubber seal unit rotates with and seals around the drill pipe and tool joint when drilling, making connections or tripping in or out of the hole.

The three main types of CPD methods are air drilling (AD), managed pressure drilling (MPD) and underbalanced drilling (UBD). AD is geared toward increasing the rate of penetration (ROP), MPD reduces rig non-performance time, and UBD minimizes reservoir damage and increases productivity.

Well GT 1 was drilled using two of these CPD methods as it varied temporarily from at-balance to underbalance conditions using nitrified fresh water, with the intention to avoid continuous influx to surface. Accordingly, the drilling method could justifiably be termed CPD, MPD or UBD. For this article, the four runs undertaken will be referred to as UBD Runs 1, 2, 3 and 4 even though the well was not strictly continuously in underbalance conditions.

Table 1: Well GT 1 was planned as a 3-B-4 under the IADC Well Classification System for Underbalanced Operations and Managed Pressure Drilling. The well’s open-hole section was drilled in two phases using a total of four UBD runs.

Planning

Well Classification

IADC’s well classification system for underbalanced operations and managed pressure drilling (MPD) describes a well using a three-digit code based on overall risk, application category and fluid system.

Based on this system, GT 1 was planned as 3-B-4:

• Overall risk was Level 3: geothermal and non-hydrocarbon production. Maximum shut-in pressures less than UBD equipment operating pressure rating. Catastrophic failure has immediate serious consequences.

• Application category is Category B: underbalanced operations. Performing operations with returns to surface using an equivalent mud weight that is maintained below the open-hole pore pressure.

• Fluid system is 4 (gasified liquid): fluid medium with a gas entrained in a liquid phase.

Table 2: Minimum liquid flow velocity was an important input parameter during pre-job and rig-site modeling of multiphase flow using a simulator. It determines the cutting-carrying capacities. Table 2 shows the values for minimum hole-cleaning capacities for water-based mud based on experience.

Objectives

The objective of GT 1 was to drill the 9 ½-in. open hole to TD using CPD methods with the following criteria:

• Drill the open hole with a two-phase water and nitrified fluid to maintain CPD conditions in the open hole, avoiding reservoir damage;

• Avoid drilling problems such as mud losses, differential sticking and potential kicks by proper fluid control and measurement; and

• Allow potentially faster ROP and lower total drilling days. This was a secondary objective compared with the primary objective of avoiding losses.

By successfully using CPD methods, the following results may also be possible:

• Drill to TD with full returns, allowing collection of geological information;

• Reservoir/production evaluation and characterization while drilling; and

• Gather data for drilling performance optimization and future well planning.

Modeling

Pre-job and rig-site modeling of multiphase flow was done using an advanced simulator to determine the required underbalanced drilling conditions. These include the following input parameters:

1. Gas-to-liquid ratios are evaluated and selected to reduce the hydrostatic pressure within the annulus to achieve the desired bottomhole circulating pressure.

2. Minimum liquid flow velocities, which determine the cutting-carrying/hole-cleaning capacities. By experience, the values for minimum hole-cleaning capacities for water-based mud are:

• Well trajectory: minimum required velocity;

• Horizontal: 55 meters/min; and

• Vertical: 45 meters/min;

3. The mud motor equivalent liquid volume (ELV) is taken into consideration. This value cannot be exceeded.

4. The gas volume fraction (GVF) in the drill pipe can affect downhole tool performance.

Figure 2 shows the structural placement of the GT 1, GT 2 and GT 2a wells in the Kirchweidach Geothermal Project. GT 2a had the most challenging well path as it targets a fault to the north and has inclinations of up to 97° for a long section. CPD equipment was therefore rigged up before the expected losses zone rather than after the losses appeared in GT 2a.

Modeling was performed using data provided by GEOenergie Bayern and known physical constants. To function, Neotec requires a number of input values, including the specific gravity of the intended drilling fluid, composition of the injected gas, borehole trajectory and annular design. Additionally, drill string design, including tubular profiles and operating limits (pressure drop and max motor ELV), are of interest as points of increased annular friction or pressure drop, which can affect downhole fluid velocity.

Estimations are substituted. Initial indications were that target formation pressure was 351 bar (5,089 psi) and formation temperature was 145°C (293°F). Reservoir pressure was thought to be 383 bar (5,555 psi) at TD. Offset wells reported partial to total loss scenarios when drilling with 1.02 to 1.05 sg (8.4 to 8.7 ppg).

A primary requirement of the CPD operation was to reduce annular friction pressure, which is responsible for increases in the bottomhole pressure and the potential for fluid loss. A solution was to establish a high nitrogen injection rate with a moderate fluid injection rate. This also increases the fluid velocity, which aids hole cleaning. When working in a very narrow pressure window, the case where the well is not producing at the casing shoe is considered the worst-case scenario.

Fluid injection rates were designed to lie within the capabilities of the equipment available while not exceeding reservoir pressure draw-down of 10%. Initial modeling was conducted with rates varying from nitrogen at 18 cu meters/min to 28 cu meters/min and fluid injection at 2,000 lpm to 2,600 lpm.

An operation envelope was created that identified an optimal injection rate of 22.6 cu meters/min of nitrogen and 2,400 lpm of drilling fluid with a density of 1.02 sg. This produced a reservoir draw-down of 4 bar (58 psi) while remaining within operating limits of less than 18% GVF (5%) and motor ELV limits.

However, these injection rates provide hole-cleaning velocities of 41 meters/min in the vertical section. Experience has shown that under these conditions, adequate hole cleaning can be achieved through the scheduled pumping of high-viscosity pills, reciprocating the drill string prior to connections and low ROPs. On the other hand, should the reservoir flow, vertical and horizontal fluid velocity would exceed their minimum thresholds, and hole cleaning would be vastly improved.

While concentric casing and parasitic string injection methods were known to be highly effective nitrogen injection methods, drill pipe injection was chosen as it was shown to be adequate.

Nitrogen

There are two methods for getting the required supply of nitrogen on the rig site.

Cryogenic nitrogen is widely used in drilling operations as it is transported to the well site as a liquid, and the boiling point of liquid nitrogen is -196.1°C (-321°F) at atmospheric pressure. Cryogenic tanks are necessary for transportation and storage on location.

Because the nitrogen is pumped as a liquid and the conversion from liquid volume to gas volume at standard conditions is well characterized, it is straightforward to accurately measure and control the nitrogen delivery rate. This also comes with a guaranteed nitrogen purity of 99%, which vastly reduces corrosion effects on equipment.

Membrane nitrogen involves stripping nitrogen molecules from the local atmosphere. This system has different equipment requirements to the cryogenic method, but once the sourced nitrogen is in the standpipe, it provides the exact same function.

Regardless of the nitrogen source, it eliminates the possibility of downhole fires. Pure cryogenic nitrogen also prevents downhole corrosion due to the purity level. Membrane-generated nitrogen contains some oxygen, and downhole corrosion remains a concern. Awareness of corrosion effects is crucial to safe operations and equipment maintenance. Other factors need to be considered before it is decided to use cryogenic or membrane nitrogen, such as cost, availability, site layout and available space, diesel consumption, and noise control.

Based on the above criteria, the plan was to drill GT 1 using cryogenic nitrogen.

Development

Equipment Selection

The CPD geothermal package was designed to have an efficient and minimal on-site footprint. The Model 9000 RCD was perfectly suited for the well conditions projected with 34 bar (500 psi) operating pressure rating, and they close the annulus to the rig floor. RCDs are not well control equipment, and no CPD equipment was labeled as such.

An adapter and two drilling spools were installed between the top of the blowout preventer and the base of the RCD. One of the drilling spools had outlets to connect to the 8-in. flow line and the injection of cold water across the top of the well. The purpose was to ensure heated fluids did not decrease the expected life span of the rubber sealing element.

Between the wellhead and the geothermal separator, a globe valve was installed to regulate flow from the well to stem intermittent slugging from the annulus that was expected to occur. In the top-hole section of the annulus, nitrogen becomes free to rapidly expand due to a decrease in hydrostatic pressure, resulting in slugging at surface. The globe valve was a simplified and recognized method of manually applying surface back pressure to control the release of this fluid.

An 8-in. flow line and a geothermal separator with adjustable frame to match the shaker tank height complete the return flow system. The geothermal separator is where the nitrified drilling fluid is first exposed to open atmosphere and was designed to effectively allow the separation of nitrogen from the drilling fluid. This equipment employs the principle of centrifugal force for liquid-gas separation as in cyclone equipment. The nitrogen-free liquid then goes down to the shale shaker and back into the pits. The geothermal separator has 8-in. inlet and outlet flow lines, and the inside of the separator is lined to reduce erosion.

Data acquisition equipment on-site recorded flow-out temperature and pressure. Also monitored were nitrogen injection pressure, temperature and flow rate. Nitrogen pump pressure must be high enough to entrain nitrogen in the stand pipe. All data was available and transmitted via the rig-site WITS network.

Float subs were inserted to the top of the drill string to prevent the upward migration of nitrogen when the rig pumps were turned off. This increased safety, reduced wasted nitrogen and reduced time spent bleeding the drill string when making a connection.

Drilling Procedures

A number of drilling procedures were drawn up aimed at increasing the preparedness of the rig crew for events that could occur and aid steps to reach TD as quickly as possible without taking shortcuts. These issues had to be addressed before operations commenced as many personnel were being exposed to closed-loop and hydrostatic balance manipulation methods for the first time. This was a critical step toward ensuring personnel and equipment safety on the rig site and mitigating drilling hazards.

Drilling with nitrified fluid creates scenarios that conventional drilling operators may not be familiar with. Therefore, procedures were translated into German and circulated to the relevant people.

In addition to normal UBD operation procedures, rig crew were presented with the information that would allow them to react to equipment failures, well control and ESD events in which the presence of nitrogen would be a factor to consider. Another critical factor to account for was the communication between rig floor and the nitrogen injection crew. Standard rules for radio communication and reporting were established.

Operations

The GT 1 open-hole section was drilled in two phases using four UBD runs. Initially, UBD Runs 1 and 2 were drilled from the 10 ¾-in. liner shoe at 3,664-meters to 4,503-meters MD. A subsequent acid job and well test proved unsatisfactory, so the UBD separation and nitrogen injection packages were rigged up again. UBD Runs 3 and 4 were drilled from 4,505-meters MD to 4,937-meters MD.

UBD Run 1

This run was conducted from 18-25 February 2011. A 3-meter rat hole was drilled beyond the 10 ¾-in. liner. The run initially started well with full returns and a low

Figure 3: A high nitrogen injection rate with a moderate fluid injection rate was established to reduce annular friction pressure, which is responsible for increases in the bottomhole pressure and the potential for fluid loss. An operational envelope was established at the 10 ¾-in. liner shoe that identified an optimal injection rate of 22.6 standard cu meters/min (800 standard cu ft/min) of nitrogen and 2,400 lpm of drilling fluid with a density of 1.02 sg.

nitrogen rate, which kept the operation slightly overbalanced. Nitrogen injection rates were gradually increased to 14 cu meters/min and held steady at this rate as the UBD system was effective in lowering the equivalent circulating density.

Although this is below the initial model predictions, this left room to increase if desired. On 23 February, it was found that LWD transmissions were very noisy, and signals were not received with a nitrogen flow rate over 12 cu meters/min. A compromise was made to maintain flow rates to ensure adequate data transmission from the tool to the surface. This effectively increased the ECD and ESD, and the system was not truly underbalanced at all times, but it enabled the rig to continue drilling in the given circumstances.

Foaming issues became a problem on 19 February due to the reaction of the drilling fluid polymer (xantin gum) with nitrogen. The initial solution of adding a defoaming agent proved to temporarily solve the issue, but the problem persisted and the system became unmanageable.

The decision was taken to completely replace the drilling fluid in the pits with fresh water without any polymer. Although this was not ideal, returns were recorded on surface, and it helped decrease the daily costs for drilling fluid.

On 25 February, with ROP consistently low at 1 meter/hr, the decision was made to pull out of hole and change the bit. At this point, the bit had spent 96 hrs on bottom. An average instantaneous ROP of 11.6 meters/hr across for this run was recorded, which was decreased by the time spent drilling with the greatly deteriorated bit.

UBD Run 2

A second UBD run was started with a new bottomhole assembly run in hole on 26 February. On this occasion, LWD signal transmission was greatly improved at nitrogen injection rates of 16 cu meters/min. LWD data transmission was lost on 27 February at a depth of 4,219-meters MD. Neotec calculated ECD and bottomhole pressure in line with LWD output prior to end of transmission. The decision was taken to continue to drill ahead without MWD directional guidance.

From here on, knowledge of bottomhole conditions was solely based on the calculated model, which until this point had tracked MWD readings with great satisfaction. For this run, increased emphasis was placed on pit volume tracking. It was in this bottomhole section that significant formation fluid gains were taken while drilling UBD as the reservoir was induced to flow to surface.

Increased torque was experienced while backreaming before connections from a depth of 4,320-meters MD. TD was called at 4,503-meters MD on 2 March 2011. Due to the lack of MWD guidance, the planned hole trajectory was not properly followed. Cave systems and pronounced fractures along the well path explain periods of diverse drilling parameters and pit volume changes.

Traditionally, cave systems add complexity to UBD jobs as they can cause both high fluid gains and losses at surface. These may have been a location of temporary cuttings storage. On flowing the reservoir when pulling out of hole and during the wiper trip, this may have been a source of cutting re-injection back into the annulus.

An average instantaneous ROP of 8.5 meters/hr was recorded for this run.

UBD Run 3

UBD Run 3 started after the stimulating and test work done in the well gave unsatisfactory results, and the decision was made to extend the well to try to reach the main fault. This time CPD was paramount to get returns while circulating as the losses were above 140 cu meters/hr, and the available supply of water was 60 cu meters/hr.

Early attempts to initiate full conventional circulation failed, with the rate of fluid losses to formation too high to maintain the required surface pit volume to continue drilling. Drilling eventually commenced with the sourcing of additional water supply.

On 17 April, annular injection started with a two-phase fluid of water and nitrogen being pumped between the 20-in. surface casing and 13 ^3/8-in. concentric casing. As this operation progressed, nitrogen injection was gradually increased as drilling fluid injection was decreased. This continued until it was possible to just pump nitrogen in the annular cavity.

The rig pumps were then realigned to start pumping drilling fluid down the drill string, and rotary drilling commenced. This dual-injection method worked initially with optimal rates of 2,000 lpm of drilling fluid and 10 cu meters/min of nitrogen.

A decision was made to investigate the effect of increasing annular nitrogen injection from 10 cu meters/min to 20 cu meters/min. This proved less optimal, and the nitrogen rate was returned to 10 cu meters/min. However, this had the effect of essentially super-charging the annular cavity with nitrogen. As this nitrogen rounded the concentric casing perforations, high-pressure slugging resulted in the well blowing itself dry. Concentric casing injection was halted, and nitrogen was realigned to pump down the drill string.

The presence of this concentric casing, however, was beneficial for the fact that the annular pressure drop was decreased, making it easier to lift cuttings out of the hole.

At 4,540-meters MD, a short trip was performed, and the string was pulled back to 3,555-meters MD. Annular nitrogen injection was halted, and the operation resumed with just drill pipe injection. Injection rates of 2,000 lpm drilling fluid and 10 cu meters/min nitrogen remained optimal values for maintaining adequate fluid return rates to continue drilling. Return rates were typically 50% of volume pumped, which was typically calculated to be a loss of 60 cu meters/hr. The high loss rate is attributed to the acidizing job that was performed after UBD Run 2. The increase in size of fissures and fractures led to increased permeability. A high proportion of fluid pumped from surface was lost to the formation, with nitrogen moving to the high side of the horizontal section, where it too was mostly lost to formation. It is believed some volume of nitrogen did return to surface, but this was very minor with respect to the volume injected. However, the presence of the nitrogen was responsible for decreasing the hydrostatic head sufficiently that some formation fluid influx was induced in the open-hole section above acidized zone.

Further, nitrogen prevented sticking at tight spots along the well path that developed in the later stages of UBD Run 2.

Figure 4: The initial planned well profile for GT 1 was changed when TD was extended. The scope was originally to drill the well underbalanced through the Malm reservoir carbonates to 4,720-meters MD to evaluate and exploit the geothermal properties of the reservoir. After four underbalanced drilling runs, TD was called at 4,937-meters MD. By extending the well depth, objectives were achieved. This was enabled by the use of controlled pressure drilling techniques.

At 4,670-meters MD, drill pipe injection rates were increased to 2,500 lpm and 15 cu meters/min. A bit trip was called at 4,726-meters MD. The average instantaneous ROP for UBD Run 3 was 15.3 meters/hr.

UBD Run 4

UBD Run 4 drilling commenced with fluid and nitrogen injection rates varying from 2,300 lpm to 2,500 lpm and 15 to 20 cu meters/min respectively. This run was rather uneventful compared with UBD Run 3. Average ROP for the section was 9.6 meters/hr. Improved returns were viewed, and this is likely due to the eventual plugging of fractures and fissures, as well as formation of skin on borehole walls. A number of pills were pumped after TD, and this helped clean the hole of a large quantity of cuttings.

The drill string became stuck while pulling out of hole, and the re-introduction of nitrogen was found to aid the recovery. Reduction of differential sticking is a long-recognized benefit of UBD and previous wells in this locality have all run into pipe stick problems at shallower depths.

The temperature of returns at surface was noticeably below that experience on UBD Runs 1 and 2. This is a strong indicator that water was being produced from above the acidized zone at shallower depths. LWD data is the best source for bottomhole temperature comparisons. TD was called at 4,937-meters MD (3,793.3-meters TVD) at 17:35 on 27 April 2011. An additional concern with the rig was the drill string weight approaching the maximum pulling capability of the rig.

Lessons Learned

Problems stemmed from the MWD/LWD failure in UBD Run 2 and the decision to drill on.  Several points were noted regarding the tool build, and MWD/LWD tool performance at high pump rates for UBD Runs 3 and 4 was greatly improved. Electromagnetic measurement-while-drilling tools were cost-prohibitive but would have not suffered annular fluid composition-related interference. In the end, improved tool design was sufficient, and perfect detection was recorded at the elevated pump rates. Additionally, the mud motor was changed from 6 ^5/8 in. for UBD Runs 1 and 2 to 8 in. for UBD Runs 3 and 4. This also enabled a greater motor throughput, raising the ELV.

While concentric casing injection was not a success in this case, its presence in the annulus for UBD Runs 3 and 4   indicated further analysis needs to be done for the concentric drilling method before applying it in the future.

Without accurate flow detection rigged up on the flow line, watching pit volume gains and losses is crucial to understanding the downhole performance of the system.

Foaming was not initially accounted for and provided some adverse drilling conditions. Preemptive and aggressive defoaming is essential for nitrified drilling fluid operations. In a very active system this is not always possible, but it is highly recommend.

Using concentric casing carries a risk, which may not be worth the investment in rig modification as the drill pipe injection method used on GT 1 has proven successful. It is strongly advised to employ this method on future UBD wells in this region.

The application of multiple float subs and NRV’s greatly reduced time spent bleeding nitrogen from the drill string once the rig pumps were shut down. The GT 1 well introduced UBD technology to the rig crew and other service companies, which inevitably caused some confusion and problems, especially when adding the language barrier between the rig crew and the UBD crew. This is expected to greatly improve in future operations where the rig crew has a better understanding of the equipment and techniques used during UBD operations.

The knowledge that the UBD crew has acquired of the rig and the location will also aid in improving future operations.

Conclusion

The scope of this operation was to successfully drill the GT 1 well underbalanced through the Malm reservoir carbonates to a depth of 4,720-meters MD to evaluate and exploit the geothermal properties of the reservoir. After four UBD runs, TD was called at 4,937-meters MD. The expected test results were not achieved on the first attempt, but after extending the well to its final TD of 4,937 meters, the well objectives were accomplished.

The use of CPD was a key factor for the efficient drilling of the extension.

UBD techniques enabled GT 1 to achieve a greater depth than any known well previously drilled in this locality. Additionally, the ability to achieve 100% returns is a vast improvement over conventional techniques previously applied in the area. Total loss situations were avoided on UBD Runs 1 and 2.

Ultimately, UBD permitted GT 1 to be drilled to a point where well testing could be possible with reduced formation damage due to the invasion of drilling fluid solids.

While the original well path was changed, drilling the longest open-hole section in the Malm reservoir allowed it to hit all the planned targets, providing significant information about the target reservoir. Moreover, extending the well TD to 4,937-meters MD in the Malm reservoir allowed a significant achievement by hitting the main fault in the area at +/- 4,900-meters MD. Achieving this objective will greatly aid future drilling in the region as well.

All of this would have not been possible without the aid of nitrified drilling fluid mitigating drilling hazards and lowering the annular hydrostatic pressure head.

The injection of nitrogen into an annular space created with a concentric casing string needs to be carefully planned and considered in the well design, otherwise it will lead to problems with the surface equipment due to irregular underbalanced conditions.

The use of annular pressure and temperature sensors can greatly assist in the determination of the rate of nitrogen to be pumped during drilling and can show influx/loss zones.

Although CPD was not used in the GT 2 and GT 2a wells, it was ready to be deployed and was considered as the technical solution to continue drilling if severe losses would have appeared. It is recommended to include early in the planning stages of the well design in geothermal projects in the area the use of CPD as an option to allow the reaching the well objectives in case total losses appear.

This article is based on SPE/IADC 156895, “Successful Controlled Pressure Drilling Application in a Geothermal Field,” 2012 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Milan, Italy, 20–21 March 2012.

By Katherine Scott, editorial coordinator

An increasing US crude production coupled with declining oil demand is resulting in a sharp reduction in the nation’s oil imports, according to Raymond James and Associates. They believe that US oil and gas companies have already worked toward reversing a nearly four-decade-long decline in oil supply. Source: EIA, RJ estimates

Horizontal drilling and multi-stage fracturing are working hard for the industry, and the results are paying off. According to research by Raymond James and Associates, by opening the door to vast resources of unconventional liquids, the industry has radically reshaped the trajectory of US oil production. This is reversing a nearly four-decade-long decline in oil production.

Coupled with declining US oil demand due in part to better vehicle efficiency, the shift is moving the country toward energy independence. Owed to fact that US oil and gas companies have already overcome government road blocks and geological challenges to increase oil supply, and a change in transportation habits has decreased oil demand, Raymond James expects that US net oil imports could reach essentially zero by 2020.

On 22 March at Ohio State University, US President Barack Obama made the claim that the US cannot become energy independent solely by doing more drilling, saying that “we can’t simply drill our way out of the problem.”

Marshall Adkins, managing director, head of energy research for Raymond James, strongly disagrees. “The facts say something very different. The facts say that we are drilling our way out of this. (We’re moving toward being) totally oil independent.”

The recent boost in US oil production, which reached 8.1 million bbl/day last year, and cuts in oil demand are causing imports to fall, which Mr Adkins said is a major part of attaining oil independence for the US.

“It appears that demand will continue to drift lower, but the real driver is more supply, so you combine roughly two barrels of supply growth for every one barrel of decline in demand, and you’re getting pretty meaningful reduction in the amount of oil we need to import,” he explained.

Increasing oil supply

Research by Raymond James suggests that the US produced more incremental oil supply than any other country from 2009 to 2011. The growth doesn’t stop there; it is projected that, compared with 2011, there will be a 6% increase in oil production this year and an average 11% growth per year between 2013 and 2015, most of it driven by the ongoing surge in onshore volumes. The use of horizontal drilling and multi-stage fracturing in areas like the Bakken, Eagle Ford and Permian Basin is allowing the industry to get more oil out of the ground.

Declining oil demand

Likewise, Raymond James projected that there will be a base decline in oil demand of 1.5% each year through 2020. US oil demand peaked in 2005 at 20.8 million bbl/day, having grown in every year but one since 1992. However, since then, demand has fallen in every year but one, and Raymond James estimates that there will be a decline of 2.5% for 2012 relative to a year ago.

Mr Adkins said that the decline in US oil demand has largely come from higher energy prices, which in turn are pushing better vehicle efficiency, more natural gas vehicles and reduced travel patterns.

Falling oil demand is a smaller but relevant part of the overall story. US oil demand has fallen in every year but one – even in the good economic years of 2006-2007, according to Raymond James and Associates. Source: EIA, IEA, RJ estimates

Decreasing oil imports

In light of this increased supply and decreased demand scenario, Raymond James concluded that the US is poised to sharply decrease its dependence on other countries for imported oil. Their research shows net US oil imports already falling from 13.5 million bbl/day (65% of demand) in 2005 to approximately 9.8 million bbl/day (52% of demand) in 2011, and that may fall to an estimated 4.5 million bbl/day (26% of demand) by 2015.

Additionally, lower oil import costs could stimulate resurgence in US manufacturing, bringing with it more jobs.

“This is also a huge boom to US labor, across the board. It’s not just in the energy business, but you know cheap energy creates more manufacturing jobs,” Mr Adkins said, “The single biggest, most visible and immediate benefits to this … is more jobs.”

US trade deficit

Another important aspect to consider is the US trade deficit, where oil imports play a large role. According to the research, oil imports have generated more than half of the total deficit every year since 2007.

“(Decreasing oil imports is) hugely positive for the trade deficit. In the last several years, over half of our trade deficit has been energy related, and if you eliminate that, then your trade deficit gets cut in half,” Mr Adkins said.

Despite adding to the total deficit, the net oil import requirement has dropped every year since 2005, with further declines projected. With an approximately 2.2 million bbl/day reduction in imports since 2008, the US has reduced that part of the deficit by approximately $80 billion annually.

Mr Adkins believes that the resulting savings in the trade deficit are highly meaningful, especially when the benefits of cheaper energy for US manufacturing are taken into account. Further, their research states that the trends of lower oil import costs, cheaper US natural gas prices and decreasing non-oil related trade deficit point to a reduction in the total US trade deficit of 82% by 2020.

Despite these findings, however, Mr Adkins believes there are still additional steps that need to be taken. “(If we increase access to drilling), it will speed up the process of becoming energy independent.”

FMC to supply Petrobras with subsea equipment

FMC Technologies recently signed a four-year agreement with Petrobras for the supply of pre-salt subsea equipment.

FMC’s total scope of supply could include the delivery of up to 130 subsea trees, subsea multiplex controls and related tools and equipment.

The tree systems are for use offshore Brazil in water depths up to 8,200 ft (2,500 meters). The equipment will be engineered at FMC’s South American Technology Center and manufactured at the company’s subsea facility, both located in Rio de Janeiro.

The subsea trees will achieve 70% Brazilian local content, and deliveries are scheduled to commence in 2014.

Gazprom awards Expro three PVT contracts in Iraq

Expro has secured three contracts in Iraq. The trio of contract awards adds to a recent contract with Eni.

Expro will undertake analysis of more than 100 pressure, volume and temperature (PVT) studies in a contract award with Gazprom in the Badra field close to the Iranian border. Two further contract awards with large operators in the south of Iraq involve further PVT sampling studies and laboratory work.

Expro will utilize its Iraqi capabilities, as well as its fluids analysis center and analytical data services teams in the UK, to conduct more than 200 PVT studies.

Baker Hughes facility targets unconventional resources

The Baker Hughes Dhahran Research and Technology Center recently opened in Saudi Arabia with a focus on research and development of new technologies to unlock the potential of unconventional resources.

The technology and research center is a partnership between Baker Hughes and Saudi Aramco.

The center brings together the competencies of Baker Hughes engineers and scientists of Saudi Arabia and King Fahd University of Petroleum and Minerals to develop application-specific solutions. With rock and fluids laboratories, the center provides equipment to understand the science and technology in developing unconventional resources.

Transocean’s global training center in Macaé opens

Transocean’s training center has opened in Macaé, Brazil, in the city’s busiest industrial center. The facility provides the latest in technology and teachings. The company plans to install a cyber-based drilling simulator to train drillers who work on the latest-generations of offshore rigs.

Estimated demand this year is more than 200 classes for personnel from Brazil and other Transocean locations worldwide. For the first time in Brazil, Transocean personnel can take drilling and crane operations competency assessment classes, D-CAP and C-CAP, using simulators onshore, in addition to offshore assessments.

Murchison Drilling Schools expands in Houston

Murchison Drilling Schools (MDS) has opened a Houston training center (HTC). MDS offers weekly IADC and IWCF well control courses, a five-day practical drilling technology course, a five-day advanced drilling technology course and a floater operation transitions course.

Additionally, Willie Lyon has been promoted to vice president and manager of the HTC. E.B. Clapp has joined MDS as manager of well control at the HTC.

Tim Arnold has been promoted to manager of training at the Albuquerque training center, and Bill Murchison Jr. has been promoted to president of MDS.

Andy Hendricks joins Patterson-UTI as COO

William Andrew “Andy” Hendricks Jr joined Patterson-UTI Energy as chief operating officer in April. Mr Hendricks served since 2010 as president of Schlumberger, drilling and measurements division.

It is expected that Mr Hendricks will assume the position of president and CEO upon Doug Wall’s retirement this year.

Stephen Oswald joins Capital Safety as CEO

Stephen Oswald joined Capital Safety in March as its new CEO.

For the last 15 years, Mr Oswald had held various executive roles at United Technologies Corp (UTC), most recently serving as the integration leader for UTC’s acquisition of GE Security.

Burleson appointed director at Cudd Energy Services

Larry Burleson has been appointed director of business development for corporate services at Cudd Energy Services. Mr Burleson will provide leadership in building a global clientele for the company’s integrated solutions. He joins Cudd Energy from Weir Seaboard, where he was vice president of sales.

Tekena Dokubo, GL Noble Denton

Dokubo to lead GL Noble Denton’s new Nigerian base

GL Noble Denton has opened its first base in West Africa with operations in Lagos, Nigeria. The company’s Nigerian operations will provide services and software solutions to aid international and local oil companies in developing and operating safer and more efficient assets in West Africa.

Tekena Dokubo has joined the company to lead GL Noble Denton’s presence in Nigeria. Mr Dokubo brings experience in business development in West Africa’s oil and gas sector.

Vantage Drilling acquires Dragonquest drillship

Vantage Drilling has signed a definitive agreement to acquire the rights and obligations under the construction contract for the ultra-deepwater drillship Dragonquest from Valencia Drilling.

Dragonquest was constructed at Daewoo Shipbuilding & Marine Engineering Co in Okpo, South Korea.

Schlumberger to acquire modeling software company

Schlumberger has entered an agreement with Altor Fund II to acquire SPT Group, which specializes in dynamic modeling. The company provides software and consulting services for multiphase flow and reservoir engineering.

“The dynamic modeling and reservoir optimization software of SPT Group will complement the existing Schlumberger production software portfolio,” Tony Bowman, president, Schlumberger Information Solutions, said.

PRODUCTS

Exxon MZST licensed to Weatherford subsidiary

ExxonMobil Upstream Research Co (URC) has licensed its Multi-Zone Stimulation Technology (MZST) well treatment process to a subsidiary of Weatherford International. The MZST process can be used to stimulate multiple zones in a single operation, yielding improved well economics.

The MZST process can be beneficial for hydraulic fracturing operations in tight gas, shale gas and coal bed methane wells that target multiple reservoir zones, thick reservoir sections or long reservoir intervals where multiple stimulation treatments are required.

“The MZST process is a proven technology for rapidly completing wells in tight reservoirs such as shale gas,” URC president Sara Ortwein said. “This technology will play a key role in improving the economics of developing this unconventional resource.”

The MZST process will enable Weatherford to optimize its stimulation operations by combining the deployment of perforating and hydraulic fracturing equipment simultaneously in the wellbore to enable “single-trip” multi-zone stimulations. The technology increases the number of zones that can be fractured per day compared to traditional fracturing and stimulation operations.

Halliburton’s Q10 pump meets shale fracturing demands

Halliburton has rolled out the first production unit of its new Q10 pumping trailer. The redesigned Q10 pump enhances performance while reducing pumping assets at the well site.

The Q10 units target shale fracturing applications. Performance specifications include a maximum pressure rating of 20,000 lbs/sq in., a range of rates between 2.7 and 18.9 bbl/min, and a power rating of 2,000 hydraulic horsepower.

ConocoPhillips’ Wireline Lubricant designed for HPHT

ConocoPhillips recently launched a new wireline lubricant designed to maintain a seal and prevent the escape of wellbore fluids during wireline operations. Wireline Lubricant is a specialized, clear formulation designed specifically for high-pressure, high-temperature environments.

The lubricant was developed for wireline operations, including cased-hole logging, pipe recovery service, production loggings and reservoir analysis.

Schlumberger’s LWD service supports formation evaluation

Schlumberger recently introduced the MicroScope high-resolution resistivity and imaging-while-drilling service. On a single collar, the logging-while-drilling service provides high-resolution laterolog resistivity and full borehole images in conductive mud environments.

The service has been successful in more than 150 jobs and addresses challenges in unconventional shale plays, carbonate and clastic reservoirs.

Gloves reduce hand fatigue, enable safer work

To safeguard often-forgotten impact and pinch points in high-impact situations, Mechanix Wear’s M-Pact EXP-2, being released in May, has an extended, embossed vinyl cuff designed to dull potential impact to the outer wrist.

The anatomically designed palm pads reduce hand fatigue when the grip is engaged, enabling faster, safer and cleaner work with more power and control.

Mud mixers feature high-efficiency gearboxes

Chemineer mixers offer performance, efficiency and reliability in mud-mixer applications. The Chemineer mixers feature high-efficiency gearboxes designed for agitator service and have configurations to meet application requirements that are unique to mud-mixing applications.

Nomac Drilling’s Rig 245 drills well Gribi 1-9-1 3H in Tuscarawas County, Ohio. Photo courtesy of Chesapeake Energy Corp

By Katie Mazerov, contributing editor

The paradigm has shifted. US land rigs that just two years ago were at work in prolific shale gas plays are on the move, delivering an oil and liquids boom that has yet to be fully quantified. Whatever trends are occurring globally, US shales are the big story for 2012, driven by new play discoveries, technology advances and favorable pricing. Drilling contractors are seeing steady and rising dayrates and high utilization as operators shift their focus from the dry gas basins and set their sights on liquids-rich regions, such as the Bakken, Eagle Ford and the Niobrara, along with emerging plays believed to hold huge reserves.

“There’s a boom going on,” said professor Jeremy Boak, director of the Center for Oil Shale Technology and Research and chair of the Oil Shale Committee’s Energy Minerals Division at the Colorado School of Mines. “There are three or four significant oil-producing plays in the US today and a huge amount of excitement, with companies moving rigs as fast as they can. While gas is much easier to get out of impermeable rock, the technology in multi-stage fracturing has advanced to the point that we can now produce oil and wet gas in these areas. In many regions, such as the Bakken, the best-producing horizons are in silty rocks, siltstones and dolomites that are interbedded in the shale.”

Since the industry cracked the shale oil code in the Bakken in 1999, production in the play has increased 55% per year, a phenomenal growth rate for a new resource, Dr Boak noted. “Potential for the Bakken is predicted to reach one million bbls per day by 2019, just 20 years after production started. It took the US 65 years to reach that number in conventional oil production and 40 years for the Canadian oil sands to achieve that.”

Meanwhile, there is a debate among some geologists over what to call the oil produced from shale. As the Bakken play developed, the industry called it shale oil, a term used since the early 1900s to refer to organic-rich shale that requires heating to produce oil. However, Dr Boak prefers to call shale containing liquid hydrocarbons “oil-bearing shale,” and the product, “shale-hosted oil.”

Big E Drilling’s Rig #1 operates for Rosseta Resources in the Eagle Ford.

Aside from increased production in the Eagle Ford and Niobrara plays, operators such as Chesapeake Energy are ramping up activity in the newer hot plays, including the Utica, underlying much of eastern Ohio, and the Mississippi Lime, or Mississippi Chat, spanning across northern Oklahoma and southern Kansas. The Tuscaloosa Marine play, a deep (10,000 to 15,000 ft) formation in central Louisiana and southwest Mississippi is believed to hold seven billion bbls of recoverable oil, an estimate made as far back as 1997, Dr Boak noted.

Despite concerns about hydrogen sulfide (sour gas) and high levels of produced water, particularly in the Tuscaloosa, there are no signs of a slowdown, he said. “Oil prices right now are high enough that an operator can spend a good deal of money going after the oil.”

Rates Steady and Rising

Nomac Drilling, an affiliate of Chesapeake Energy, has 113 marketable rigs with 110 active in the Eagle Ford, the Mid-Continent (including the Granite Wash, Cleveland, Tonkawa and Mississippi Lime), the Barnett, the Haynesville, the Bakken, the Marcellus and the Utica. In the Utica, Chesapeake plans to increase the rig count to 20 by year-end and to 30 by year-end 2014.

“Like most contractors, we are experiencing migration from dry gas plays to wet plays,” said Jay Minmier, Nomac president. “Fortunately, due to our relationship with Chesapeake, these changes do not impact Nomac’s utilization, only its deployments.”

Crews on Nomac Rig 245 work to drill well Gribi 1-9-1 3H in Tuscarawas County, Ohio.

Mr Minmier reports that rig rates have remained favorably steady since Q3 2011 and currently range from $18,500 in the Barnett to $29,750 in the Bakken. “Nomac’s rates are market-based so we aren’t immune to price fluctuations. We do believe that, to the extent wet plays can absorb the capacity leaving the dry plays, overall pricing will remain stable, although weakness is expected in certain areas like the Barnett and Haynesville.”

All of Nomac’s marketable rigs are either working or undergoing upgrades for upcoming jobs. “Our utilization has historically stayed between 95% and 100%, and we will be fully employed again once the upgrades are fielded,” Mr Minmier said. Twelve new rigs are slated for delivery through April 2013, with two 1,500-hp rigs for oil drilling in the Powder River, Wyo., region and 10 1,200-hp rigs for the Utica. Dual-fuel systems are being added to the majority of its fleet to allow the rigs to run on compressed natural gas or liquefied natural gas, as well as diesel.

“Many of our existing rigs and all our newbuilds have walking systems to facilitate efficient, slot-to-slot moves on a single pad,” Mr Minmier said. “Our newest rigs also include certain innovations to reduce location-to-location move times. We are focusing heavily on mobilization times as this portion of the well manufacturing process has become much more visible due to faster drilling times.”

From a technology perspective, the company has not been limited on lateral lengths. “To the extent that some laterals are shorter than preferred, it is almost always a leasing issue,” he added.

Nomac is implementing an accelerated development program for drillers, directional drillers and rig managers aimed at reducing the time required to train competent rig leaders by 60% over traditional methods, Mr Minmier noted. The program is targeted to young, motivated professionals with no industry experience.

Big E Drilling has shifted its fleet from the Haynesville to the Eagle Ford play, a move president and CEO Lyle Eastham said was justified given the current pricing environment. “We decided to go where the liquids are,” Mr Eastham said. “There could conservatively be 10 to 15 years of drilling in the Eagle Ford. When we moved into the play three years ago, there were only 30 rigs. Now there are nearly 240 operating.”

Today, the company’s five rigs are all operating in the Eagle Ford, including one the company built 18 months ago.

A Precision Drilling Super-Triple (ST) 1200 rig moves to the next well on a pad in the Marcellus play. The self-moving rig can move with a full setback of tubulars.

“We have added a lot of automation equipment, including top drives, catwalks, blowout preventer lifts and rig walking systems, to our rigs, which have enhanced safety and efficiency and aided in the contracts we’ve been awarded,” Mr Eastham continued. The fleet is designed for horizontal and directional drilling at depths from 15,000 to 25,000 ft, with dayrates in the mid-$20,000s.

But he also gives considerable credit to the company’s stable work force. “All our pushers have a minimum 20 years of experience, and we have a lot of 30-year employees with little turnover. We keep our rigs busy, and run a safe, efficient operation.”

Walking the Walk

Newbuild activity is also healthy in North America, with many of the major companies ramping up their fleets with efficient, highly mobile rigs suited for shale wells and pad drilling. Calgary-based Precision Drilling delivered 18 new rigs in 2011 and has contracts on 33 more to be delivered by the end of 2012 in North America.

“These are state-of-the-art, tier one rigs that are equipped with pipe-handling systems and integrated top drives, and all run range three (45-ft) tubulars. They are designed with a small footprint in mind,” said Doug Evasiuk, senior vice president of sales and marketing, North America for Precision.

“Pad drilling continues to be attractive to operators wanting to minimize the environmental footprint, limit truck traffic and reduce move times,” he said. “All the major companies are building rigs that have the capability to walk from wellbore to wellbore to eliminate trucks. With our Canadian roots, we understand how to do that, especially for cold-weather environments. All our rigs going forward will have walking systems or the capability to accommodate them.”

Precision’s newbuilds for the US market include seven 1,200-hp rigs and 17 1,500-hp models. All are AC Super Triple rigs. For Canada, where wells are generally shallower, the bulk of the rigs are the Precision Super Single design. The Super Single rigs also run range three tubulars and have fully automated pipe-handling systems.

Nabors Drilling USA Rig 681 (above) and Rig B4 (left) are both working in the Bakken Shale of North Dakota. Rig 681 is under contract to XTO Energy while Rig B4 is working for Hess.

“In Canada, because we have a compressed drilling season and have to be very efficient, we’ve always been focused on highly mobile rigs,” Mr Evasiuk continued. “Over the years, technology has enabled operators to drill considerably faster. Wells now are taking far less time than they did in the past, meaning we’re moving a lot more than we once did. When we’re moving, we’re not drilling the well, and that translates to nonproductive time, which is costly for our customers.”

Dayrates have been solid, particularly in the liquid plays. Precision began shifting from the dry gas plays to the liquids last year, a trend that will continue, Mr Evasiuk said. The company’s large presence in the Haynesville has shrunk from the peak level of 26 rigs to just three. “There has been enough activity in the liquids plays to absorb rigs coming out of the dry gas markets.”

Rig B4

US utilization is above the industry average. Of the company’s 150 US rigs, 104 are operating in all the major plays, including the Bakken, Eagle Ford, West Texas, Mississippi Lime and Tuscaloosa. Precision has yet to enter the Utica but has been approached by operators in that region.

As the largest drilling contractor in Canada, Precision has operations in every major basin, notably the Cardium, Viking, Duvernay, Canadian Bakken, oil sands and heavy oil. Utilization in February was around 85% but has recently declined due to the spring “break-up,” which occurs late in Q1 and can carry into Q2. The thawing makes transporting equipment difficult. Traditionally, 35% to 40% of drilling activity in Canada occurs in the winter months.

From a technology standpoint, Mr Evasiuk believes the push for longer laterals will be achieved by further development of completion designs. “The industry has the capability to go out a lot farther, but it really becomes an economic decision by the operator to determine what the length of the horizontal section should be.”

Outside North America, Precision has two rigs operating in Villahermosa, Mexico, and three in Saudi Arabia. All are 3,000-hp rigs for deeper wells.

Increasing Automation

Nabors Drilling has seen an uptick in US land rig utilization, primarily in the 1,000- to 1,500-hp size being deployed in most of the shale plays, said Denny Smith, director of corporate development. “Overall, US land rig utilization is around 80%, but utilization is virtually 100% for our rigs in the highest demand window.” He sees dayrates averaging in the mid-$20,000s.

Commodity pricing is the key driver for the shifting market, a trend that began back in 2010. The weak gas price phenomenon is isolated to North America.

Nabors initially shifted several rigs from the Haynesville to the Eagle Ford. Two years ago, 58 Nabors rigs were working in the Haynesville; today there are 26. Along with a significant presence in the Eagle Ford and the Permian Basin, the company has several rigs in the Mississippi Lime, with plans to move two more from the Haynesville. The company also plans to move one or two additional 1,500- to 2,000-hp rigs into the deep Tuscaloosa play to go after gas liquids and oil, Mr Smith said.

Nabors Drilling’s Rig 109 is working for XTO Energy in the Bakken Shale, where Nabors remains the largest drilling contractor.

Additionally, Nabors remains the biggest drilling contractor in the Bakken. By the end of 2012, the company will have 76 rigs, including several newbuilds, in the play.

“The market will continue to be this way for awhile. Gas continues to be oversupplied, in part because of the associated gas that is being produced with the liquids and oil,” he continued. “There is a broad range of pricing right now. I think there is a lot of latitude for prices to even moderate some and still keep a pretty robust market. Our customers have indicated they would continue drilling if oil prices get as low as $75 to $80 in the Bakken and $60 to $65 in the Permian.”

Mr Smith said shale production, particularly horizontal drilling, has benefitted from an increase in pad drilling and major advances in downhole logging and real-time technologies. “I think there is going to be a trend toward more automation and remote control of the drilling processes that will spark further improvement  in the next two to five years in rig efficiency, with increasing numbers of AC rigs featuring digital controls and automatic drillers.”

Through its wholly owned subsidiary, Canrig Drilling Technology, Nabors manufactures top drives and other rig systems and intelligent software technologies. At year-end 2011, the company had 119 AC rigs in the US, with 31 newbuilds planned this year. Most of the contracts are for the US market, but at least two have been designated for Canada and three for other markets. Outside the US, the market is recovering, with Nabors’ land rig count expected to increase from 116 at year-end 2011 to 130 by the end of 2012. The company saw peak activity during the seasonal Canadian market, with close to 50 rigs operating in the oil-rich Montney, Duvernay and Cardium plays, Saskatchewan, and the Horn River gas basin.

A lack of service infrastructure has led to low unconventional production in Australia. “If there is a rig operating, it will be for one well, and it will be extremely costly,” said Warrego Energy’s Dennis Donald. The company holds a permit for a block in the North Perth Basin, estimated to hold one of the world’s largest shale gas reserves.

There is more gas drilling in the Middle East, particularly Saudi Arabia. “We do the majority of the gas drilling in Saudi Arabia with very high-spec, 2,000-hp rigs with multiple blowout preventer stacks for the high-pressure wells,” Mr Smith said. Nabors also has 15 rigs in the Llanos Basin of Colombia and is drilling oil for two major operators in Russia.

An Anticipated Bonanza

But there is one area of the globe where drilling activity is at a near standstill. Despite favorable market conditions, a lack of service infrastructure is retarding progress.

Dayrates in Western Australia are at least 48% higher than US rates, despite gas prices that are $8-$10 (and rising) per gigajoule, considerably higher than North American prices, with acre lease costs of $500 or less, said Dennis Donald, a partner at Warrego Energy.

The company holds an unconditional permit to develop an 86-sq-mile block in the North Perth Basin, which is estimated to hold the fifth-largest reserve of shale gas in the world. The block contains the West Erregulla tight-gas field, which underlies the Kockatea shale play recently mapped by the US Energy Information Administration. The company plans to do seismic testing this year and begin drilling in early 2013.

Mr Donald cites lack of service infrastructure as the primary reason for the low unconventional production in the vast region, in part a function of the cannibalization of rigs being used for the vigorous coal seam gas activity in the eastern sector the country, thousands of miles away. “But with the government’s push for gas to replace diesel in Western Australia, operators have been given permission to utilize hydraulic fracturing to open up the gas shales,” Mr Donald said. “There eventually will come a tipping point, and when production does open up, this will be a massive market, and we will see a bonanza for rigs and fracturing.”

Using fiber-optic technology, Baker Hughes has developed a real-time compaction monitoring system to monitor deformations of the well. The system provides real-time data and can monitor downhole conditions to detect any issues before they become a problem.

By Joanne Liou, editorial coordinator

Drawing on proven methods and technologies, the latest developments in the realm of sand control strategically capitalize on and enhance what is known to work. The challenge to control unconsolidated sand in the reservoir is met with a portfolio of evolving solutions that are producing better, faster and cheaper results. Mindful of risks and costs, the industry cautiously approaches sand control, managing complexity while reducing nonproductive time (NPT).

“The current thinking in deepwater is selecting the cased-hole completion technique and the processes that not only provides the best, fastest completions but also one that provides the least amount of risks because the daily costs of operating in deepwater for some of these rigs range from $500,000 to a million dollars per day offshore,” Bryan Stamm, technology manager of Schlumberger sand management services, said. “It’s not often that the new technologies are actually the game-changers, but it’s properly managing the packaging of the existing technologies.”

A recurring approach shared across the industry is to evaluate the utilization and application of existing technologies, then combine them with complementary elements and tried-and-true methods to produce even better results. Operators are asking service companies to provide methods that not only control sand production but also maximize productivity and increase recovery.

“Our customers are asking us to look at lower completions from a productivity perspective, not just as widgets,” Suzanne Stewart, Baker Hughes’ product line director for sand control and lower completions, explained. “Our philosophy is to look at the payzone and provide direct connections and enhance when we can in order to maximize the conductivity and to optimize production. That way, we are offering solutions and applications, not just providing widgets.”

The market and need for sand control is omnipresent from the North Sea to West Africa to onshore North America, and it continues to grow as trends point to developing significant fields. In this article, sand control experts from Schlumberger, Baker Hughes and Weatherford International share their approaches and recent developments.

M-I SWACO’s BREAKDOWN HD breaker system helps remove some of the more difficult polymer components of the filter cake.

Schlumberger

Proper evaluation and management of sand control methods have led to some of Schlumberger’s latest developments for open-hole and cased-hole completions. Offshore, particularly in deepwater wells, standalone screens or gravel packs are typically used in open hole, while frac-pack treatments are the most common cased-hole sandface completions technique. In both open-hole and cased-hole environments, how to effectively execute sand control with high efficiency and low NPT is the ultimate goal. With multizone applications, the goal is to effectively balance the reward of installation efficiency with the risk of NPT.

An area that has seen development in new technology is wellbore displacement and cleanup. “The chemistries, hydraulics and tools have always been available, but the combination of the three is seldom looked at as a complete system,” Mr Stamm said.

In proper wellbore cleanup, cleanliness is not intuitive to the drilling engineer, but it is of paramount importance to a completion engineer for both making sure the formation is not damaged, as well as making sure debris is removed from the wellbore. Debris could cause NPT associated with completion hardware.

M-I SWACO’s WELL PATROLLER and WELL SCAVENGER tools have been effective in removing debris in cased-hole completions and illustrate well cleanliness at surface. The former acts as a downhole filter during the displacement operation, removing any residual debris and validating on surface how well the displacement performed. The latter is a vacuum debris removal tool that provides reverse circulation at the end of the workstring to enhance debris removal, especially around sensitive areas or equipment, such as open perforations, formation isolation valves or temporary plugs. Captured debris is recovered at surface.

M-I SWACO’s WELL SCAVENGER is a vacuum debris removal tool that provides reverse circulation at the end of the workstring.

Sand control is part of the bigger picture, and drilling engineers are as important to the productivity of the well as engineers responsible for the completion design. “The highest value that we’ve seen is when there is an integrated team working for a common goal, not just individual objectives, such as ‘let’s just drill the well without any regard for completion,’ or ‘let’s complete the well without any regard for how it was drilled,’” Mr Stamm said.

In open-hole completions, breaker technology is a key aspect of managing the transition from the drilling phase through the completion phase and into the production phase. “But the filter cake treatment goes in combination with the fluid with which you drill in the first place,” Charles Svoboda, director of wellbore productivity, business development at M-I SWACO, a Schlumberger company, explained. “The breaker technology and the reservoir drill-in fluids have to be specifically designed together with the common objective of successfully drilling the well, completing it and then successfully producing from the well.”

The WELL PATROLLER tool acts as a downhole filter during the displacement operation, removing residual debris and validating well cleanliness.

In a 2011 case study offshore the east coast of Trinidad, the company’s BREAKDOWN HD breaker system enabled filter cake removal in a high-permeability open-hole gravel pack (OHGP) completion. The idea was to remove the filter cake in a gentle manner and not be too aggressive by compromising the filter cake integrity before the completion process was finished. The system allows users to get to higher densities and work in divalent chemistry – a calcium-based brine, Mr Svoboda explained. “The composition of BREAKDOWN HD helps us remove some of the more difficult polymer components of the filter cake that are sometimes used.”

Starch polymers, for example, break down easily with an enzyme treatment, but other fluid loss control and viscosifying polymers are more troublesome.

In the Serrette project in Trinidad, the wells had open-hole production intervals varying from 150 ft to 500 ft and contained high-permeability rock ranging from 1 to 3.5 Darcy. The reservoir drill-in fluid was engineered to limit fluid invasion and formation damage; however, there were indications of a high probability of severe production-restricting screen and gravel-pack plugging, making the placement of the filter cake removal treatment necessary during the placement of the OHGP.

To minimize interaction between filter-cake removal chemicals and the OHGP fluid, the breaker system was implemented to minimize interaction with the divalent brine system, retain adequate breaking power to remove the filter cake and maximize productivity. The final mixing and pumping process proceeded without issues or NPT.

“It’s an extension to where we’ve been,” Mr Svoboda said. “We’re now able to work in higher densities. We’re able to remove filter cakes that before hadn’t been removed by previous technologies.”

Baker Hughes’ GeoFORM Shaped Memory Polymer Sand Control System is engineered to potentially replace gravel packs in open-hole completions. Field trials are being conducted in Europe, offshore US and Southeast Asia.

Baker Hughes

Fiber-optic technology is no stranger to the industry, but its use for well and reservoir surveillance has evolved in the past decade. Baker Hughes and a major operator have collaborated to develop a technology to monitor the deformation of well tubulars and casing, which has expanded to monitoring sand screens.

The real-time compaction monitoring system enables the monitoring of the compaction-related deformations of the well. “Multiple fiber-optics string sensors give operators the ability to gain real-time information, allowing them to make changes,” Ms Stewart said. “The biggest benefit is that the system can monitor downhole conditions and then adjust to rectify a problem before it becomes a failure.”

The operator deployed the system for the first time with a downhole fiber-optic wet connect in the Gulf of Mexico (GOM) in November 2011. The system was applied to a cased-hole frac pack and was run on a 3 ^1/2-in. fiber-optic screen, inside 7 ^5/8-in. casing. Because the application was developed with a downhole fiber-optic wet connect, “we could run the upper completion and connect, so the fibers meet downhole,” Ms Stewart explained.

The fiber-optics string engages sensors at the sand face, which allows operators to continuously monitor the reservoir with fiber optics in real time. The technology uses Bragg gratings, which is a short segment on optical fiber that reflects particular wavelengths of light and transmits all others, she continued.

Baker Hughes introduced the industry’s first downhole fiber-optic wet connect in November 2011. The system is able to run the upper completion and connect, allowing the fibers to meet downhole.

“Each grating is essentially a strain gauge, and when strain is applied to the sensing fiber, the fiber is helically wrapped around the completion to be monitored, such as casing or sand screen, and the individual gratings in the fiber stretch or contract. This strain causes a shift in the wavelength of light reflected and produces strain measurements along the length of the fiber containing the Bragg gratings.”

Bragg gratings can offer an advantage over traditional electronic gauges in harsh environments because it can withstand vibration and heat, making it more reliable.

One of the newest sand control systems, GeoFORM, is based on shape memory polymer (SMP) technology. It has been engineered to potentially replace gravel packs in open-hole completions.

SMPs, introduced by Baker Hughes in 2011, resemble the material used in automobile bumpers. If there is a dent in the bumper, the repair usually involves applying heat to the area to make the dent pop out to its original form.

“SMPs have the ability to effectively remember the shape in which they were originally formed,” Ms Stewart explained. “We take the SMP, compact it to a smaller size, and then we effectively freeze it in that condition and run it in hole and allow it to go back to its original shape.” A pipe with an SMP is run in the open hole, where it can regain its original size and effectively fill the annulus. SMPs replicate a filtration system like a gravel pack without having to pump gravel.

Baker Hughes has undertaken seven SMP field trials to date in areas including Europe, offshore US and Southeast Asia, Ms Stewart said.

Weatherford’s SandAid treatment uses zeta potential altering chemistry to create an ionic attraction between particles and prevents them from migrating while allowing for adaptation to changes in formation stresses.

Weatherford

Conceiving the downhole production enhancement business unit, Weatherford combined chemical sand control with its water conformance technology in March. “Sand production and water production go hand in hand,” Ron van Petegem, product line director of downhole production enhancement for Weatherford, said. “There are many reservoirs out there that really don’t produce any sand. The rock may have even failed already, but when water production breaks through the capillary, pressures change. You may lose other cementation from clays and then comes the sand.”

Weatherford’s new approach looks at sand and water performances in tandem. Although the two are not necessarily complementary, they also are not mutually exclusive.

The magnified views illustrate untreated (top) and treated (bottom) sand grains/fines. When SandAid is pumped into the reservoir, the positively charged chemistry is attracted to the negatively charged sand, which leads to SandAid adsorbing the particle. The solution is formulated so that only a certain amount is adsorbed by the rock.

SandAid, originally field-tested in Romania and introduced to the market in June 2009 in the GOM, is one of Weatherford’s latest technologies and is still evolving in its makeup and application. The treatment incorporates Weatherford’s patented zeta potential altering chemistry, which in itself is not new to industry, but to modify the zeta potential for the purpose of sand control and increasing the maximum sand free rate is. The modification creates an ionic attraction between particles and prevents these particles from migrating while allowing for adaptation to changes in formation stresses. “Sandstone is anionic, negatively charged, and SandAid is mostly catanionic, so when SandAid is pumped into the reservoir, the positively charged SandAid and the negatively charged sand are attracted to each other, and SandAid adsorbs to the partile,” Mr van Petegem said.

The technology is typically deployed by bullheading it down the production tubing or coiled tubing; many operators prefer to bullhead the treatment down the production tubing because of the ease of placement, Mr van Petegem said. The typical treatment consists of a brine pre-flush, followed by the SandAid treatment and a brine post-flush. “We mix on the fly, and it’s an extremely simple process,” he explained. “It also means that in almost all cases, the fluids that we pump into the well are Newtonian, and as such rate diversion becomes simple and reliable, treatments are typically pumped at matrix rates just under frac pressure.”

Part of rate diversion implies that higher-permeability zones will receive more treatment than lower-permeability ones. It is essential that the chemicals do not over-treat part of the matrix, and more SandAid solution applied does not mean a thicker coating but translate into a deeper treatment, according to Weatherford. The philosophy of the design takes into consideration the minimum amount of treatment needed for lowest-permeability of the target zone. “That’s one of the key reasons for our success,” Mr van Petegem said. “Thus, during a normal treatment, the high-permeability rock will receive a deeper treatment than the low-permeability rock.”

SandAid chemistry is formulated so that only a certain amount is adsorbed to the rock.

Weatherford has applied the technology to more than 200 zones worldwide offshore and on land. In one of its first applications in the GOM, the company teamed up with an independent operator in mid-2009, and through June 2011, the treated GOM well produced at up to three times its previous maximum sand-free rate. Prior to the treatment when the well’s performance initially declined, a number of sand control options were considered. A workover with gravel-pack or frac-pack installation was deemed too costly and not fit to the existing completion configuration. SandAid technology was selected because the treatment could be mixed with seawater and bullheaded down the production tubing and because it would not reduce permeability.

Within 24 hours of application, the well was put on production, and as of April, was still producing sand free.

The chemistry of Weatherford’s SandAid technology is based on modifying the zeta potential of anionic particles. When formation stresses change because of reservoir depletion, its chemistry adapts to the changing conditions and re-agglomerates.

“Today we have a good, reasonably well-defined operating envelope,” Mr van Petegem stated, “but as we do more jobs, we continue to learn and expand our operating envelope.”

Taking a preemptive approach to sand control, the deployment of the technology is being rerouted. Weatherford is pursuing a concept called rock strength conservation, where sand control technologies are being applied to prevent failure instead of waiting for the rock to fail.

Working with a major operator and through internal testing, indications are that by applying the SandAid technology prior to water breakthrough, deeper reservoir depletion may be possible without sand production. “Essentially all sand control methods that we have today are reactive,” Mr van Petegem stated. “We may choose to install sand control systems proactively, but in essence, they do not really start operating until after the rock fails and sand becomes mobile.”

The proactive approach is a departure from the conventional sand control philosophy and would attempt to conserve and possibly prevent sand production in the first place, Weatherford believes, making it impervious to the change that is typically caused when water production starts.

Weatherford plans to do field trials for this reservoir conservation concept by mid- to end-2012 and has seen interest from operators in West Africa and the GOM.

In a separate development, Weatherford is working with operators to pump the SandAid chemistry from a floating, production, storage and offloading (FPSO) vessel through a flowline back into the well. “The considerations there are the cleanliness of the flowline itself because flowlines build up debris,” Mr van Petegem said. Weatherford is working with an operator to find the best way to clean the flowlines from the FPSO down to the well. “This could potentially allow failed deepwater wells without an intervention vessel do a sand control treatment remotely through flowline,” he added.

Conclusion

Methods of bringing unconsolidated formation sand under control are not confined to the completion phase but also affect the drilling and production phases. The industry’s approach to sand control and traditional methods are evolving to maximize proven technologies to produce the most desirable and profitable results.

“Baker Hughes does not have an allegiance to any one particular technology,” Ms Stewart stated, “which allows us to truly evaluate the payzone and to provide the best solution.”

WELL PATROLLER, WELL SCAVENGER and BREAKDOWN HD are marks of Schlumberger. GeoFORM is a trademark of Baker Hughes. SandAid is a trademark of Weatherford.

Ensco has ordered an advanced-capability, ultra-deepwater drillship to be built by Samsung Heavy Industries in Geoje, South Korea.

The vessel, ENSCO DS-8, will be the sixth Samsung DP3 drillship in the Ensco fleet. It is scheduled for delivery in Q3 2014. The contract also includes options for two additional drillships of the same design.

Consistent with the previous five Samsung ultra-deepwater drillships ordered since 2007, the new unit will have advanced capabilities to meet the demands of ultra-deepwater drilling in water depths up to 12,000 ft and a total vertical drilling depth of 40,000 ft.

New features include retractable thrusters, enhanced safety and environmental features, improved dynamic positioning capabilities and advanced drilling and completion functionality, including below-main-deck riser storage, triple fluid systems, offline conditioning capability and enhanced client and third-party facilities.

Petrobras confirms Tupi Northeast discovery, expands exploration with BP in four blocks

Petrobras has confirmed the discovery of oil in the Tupi Northeast, in the Santos Basin pre-salt. The well, 1-BRSA-976-RJS, is northeast of the Lula field, at a water depth of 2,131 meters and 255 km off the coast of Rio de Janeiro.

The discovery was confirmed by 26° API oil samples, collected from 4,960 meters. An oil column with more than 290 meters in thickness has been identified in the pre-salt carbonate reservoirs.

Petrobras also has a floating, production, storage and offloading vessel, BW Cidade de São Vicente, in the Iracema area (Block BM-S-11) of the Santos Basin. The platform was connected to well RJS-647 at a water depth of 2,212 meters.

The platform will operate for about six months to gather data on the behavior of the reservoirs and the oil flow in the subsea lines. The information will support the development of the final production system, expected to start operations at the end of 2014.

In exploration, BP has been approved to explore four blocks with Petrobras: BM-BAR-3 and BM-BAR-5 in the Barreirinhas basin and BM-CE-1 and BM-CE-2 in the Ceará Basin.

ONRR bills $4 million for BSEE rig inspections

The US Office of Natural Resources Revenue (ONRR) has billed a total of $4,091,100 for the inspection of drilling rigs in Q1 of fiscal year (FY) 2012, specifically billing $1,397,100 in October 2011, $1,447,200 in November and $1,246,800 in December. An estimated 111 oil and gas operating companies were retroactively billed by ONRR in January 2012 after the agency received the authority to do so from Congress.

According to the Bureau of Safety and Environmental Enforcement (BSEE) NTL 2012-N02, lessees and operators have been informed that ONRR will be collecting inspection fees on behalf of BSEE, covering all bottom-founded structures, floating production facilities and drilling rigs. The NTL took effect as of
1 October 2011.

BSEE’s statistics show that 3,964 rigs on the US Outer Continental Shelf were inspected in Q1 FY12. The average weekly number of rigs and non-rig units conducting well operations was 81 in the Gulf of Mexico and 18 in the Pacific region. The Alaska region currently has one federal/state production operation and no drilling activities.

All rigs are inspected on a monthly basis.

Latshaw unveils 1,700-hp diesel-electric/SCR rig

Latshaw unveils 1,700-hp diesel-electric/SCR rig

Latshaw Drilling Co recently added Rig 18 to its fleet. The rig is a 1,700-hp diesel-electric/SCR rig with a 500-ton AC top drive unit and is skiddable for multiwell pad drilling. The rig recently moved to its first location in New Mexico and will be drilling multiple wells from the same pad, with laterals up to 10,000 ft long. The company is now building Rig 19, a 1,500-hp SCR top drive, skiddable rig with 1,600-hp mud pumps that are rated to 7,500 psi.

Ocean Rig receives Letter of Award for deepwater ship

Ocean Rig UDW received a Letter of Award in April for its ultra-deepwater drillship Ocean Rig Olympia from a major oil company. The Letter of Award is for a three-year contract for drilling offshore West Africa.

The contract is expected to commence in continuation of the Ocean Rig Olympia’s existing contract in West Africa. With this contract, Ocean Rig does not have any rigs available in 2012.

Eni starts production offshore Norway, makes discovery in Mozambique

Eni started production in April from the Marulk field in the Norwegian offshore, about 80 km from the coast. The Marulk field is the first that Eni has directly operated in Norway and is part of the PL122 license held by Eni (20%) with Statoil (50%) and DONG Energy (30%).

Marulk is a gas and condensate field, with estimated reserves of 74.7 million bbls of oil equivalent and produces 20,000 boed.

Separately, Eni recently discovered natural gas in Area 4, offshore Mozambique, at the Mamba North East 1 exploration prospect. The results of this well, drilled in the Eastern part of Area 4, increases the resource base of Area 4 by at least 10 trillion cu ft (Tcf).

The discovery improves the potential of the Mamba complex in Area 4 offshore Mozambique, now estimated to have at least 40 Tcf of gas in place.

Eni plans to drill at least four more wells this year in nearby structures to fully assess the upside potential of the Mamba Complex.

Tullow exploratory, appraisal wells strike oil in Kenya

Tullow Oil has encountered in excess of 20 meters of net oil pay in its Ngamia-1 exploration well in Kenya.

The well, in the Turkana County of Kenya Block 10BB, was drilled to an intermediate depth of 1,041 meters and has been successfully logged and sampled. Movable oil with an API rating of more than 30° has been recovered.

The Ngamia structure is the first prospect to be tested as part of a multi-well drilling campaign in Kenya and Ethiopia.

In March, Tullow’s Enyenra-4A appraisal well in the Deepwater Tano licence offshore Ghana encountered oil in sandstone reservoirs. The Owo-1 discovery wells and the Enyenra appraisal well confirm the extent of the Enyenra light oil field.

Results of drilling, wireline logs, samples of reservoir fluids and pressure data show that Enyenra-4A has intersected 32 meters of net oil pay. Pressure data from the oil leg indicates a continuous oil column of approximately 600 meters.

Talisman Energy finds light oil in Kurdamir-2 well

Talisman Energy confirmed the presence of light oil at the Kurdamir-2 well in the Kurdistan Region of northern Iraq in March.

The well flowed at unstimulated rates of 7.3 mmcf/d of natural gas and 950 bbls/day of oil and condensate, with no indications of water and no observed decline.

The Kurdamir-2 well is a re-drill of the Kurdamir-1 gas/condensate discovery well, 2 km away, which was drilled in 2009 but not completed.

Keppel wins contract to build jackup based on LeTourneau design for Perforadora Central

Keppel AmFELS won a contract to build another repeat jackup rig for Perforadora Central.

Keppel AmFELS has won a contract from Mexico’s Perforadora Central to build a repeat jackup rig.

Slated for delivery in Q1 2014, the latest high-specification unit will be based on the LeTourneau Super 116E design with leg lengths of 511 ft and the capability to drill wells up to 30,000 ft in a water depth of up to 375 ft.

Keppel AmFELS completed Tonala, an ultra-premium KFELS B Class jackup rig for Perforadora Central in 2004, followed by Tuxpan, a LeTourneau S116E rig in 2010.

Perforadora Central ordered the Papaloapan jackup in March 2011, and it is under construction and on track for delivery in Q1 2013.

“We have endured the post-Macondo challenges well,” Tan Geok Seng, president of Keppel AmFELS, said. “Having recently secured the Ocean Onyx semisubmersible major upgrade and a series of repairs, this newbuild jackup adds to a healthy workload through Q1 2014.”

Apache expands production in Faghur Basin, Egypt

 Apache Corp recently received approval of seven new development leases in the Faghur Basin, which enables the company to add 5,200 bbl/day of production in Egypt’s Western Desert.

Neilos-2, Apache’s latest Faghur Basin well, test-flowed 6,301 bbls of oil and 4.2 MMcf of gas per day. The well, 0.8 km north from the Neilos-1X discovery, was drilled to appraise the north flank of the Neilos Field and logged 33 ft of net pay in the Jurassic Safa reservoir.

BRS begins to drill its first well in Italy’s Po Valley

BRS Resources announced in March that drilling has commenced on its first well. Located in Italy’s Po Valley, it is a development well in a partially depleted field where 3D seismic technology was used to identify remaining natural gas reserves.

“Using conventional drilling techniques, it will be drilled to a total depth of approximately 6,500 ft (2,000 meters),” Steve Moore, president and CEO of BRS, said. “We have employed state-of-the-art technology to target the reserves and have minimal impact.”

US Interior Department initiates system to accelerate permits, leases

US Secretary of the Interior Ken Salazar recently unveiled initiatives to expedite the development of domestic energy resources on US public lands and Indian trust lands in the Dakotas, Montana and other states.

The Bureau of Land Management (BLM) will implement new automated tracking systems that aim to reduce the review period for drilling permits by two-thirds and to expedite the sale and process of federal oil and gas leases. The system will track permit applications through the review process and flag missing or incomplete information to reduce the back-and-forth between BLM and industry applicants currently needed to amend paper applications.

BLM expects to process 5,500 applications for permits to drill in fiscal year 2012.

Helix completes West African intervention campaign

Helix Well Ops UK’s Well Enhancer mono-hull intervention vessel has completed West Africa’s first well intervention campaign.

Helix Well Ops UK has completed a three-month campaign for West Africa’s first well intervention work and subsea well operations conducted from a mono-hull intervention vessel.

Operating the 132-meter (433-ft) long Well Enhancer, Helix performed a subsea tree change-out, well suspensions, well maintenance and production enhancement on seven wells in water depths up to 471 meters (1,545 ft). The project represents the deepest operation conducted from Well Enhancer since it joined the fleet in 2009.

Well Enhancer marks the emergence of mono-hull-based well intervention services in the region. Intervention programs delivered from mono-hull vessels can provide operational and cost benefits to operators.

“Because Well Enhancer deploys more quickly than a rig and is designed specifically for well intervention work, she reduces down time and helps operators return as quickly as possible to their business of oil and gas production,” Steve Nairn, Helix Well Ops regional vice president of Europe and Africa, said.

North Atlantic confirms order of harsh-environment semi

North Atlantic Drilling has entered a turnkey construction contract with Jurong Shipyard in Singapore for the construction of a new harsh-environment semisubmersible drilling rig.

The rig will be of a Moss CS60 design, N-Class compliant and be fully winterized.

BG Group begins first production from the Gaupe

BG Group has begun production from the Gaupe field in the Norwegian North Sea. With estimated gross recoverable reserves of approximately 30 million bbls of oil equivalent, production from Gaupe is expected to reach a plateau production rate of around 15,000 boed in Q3 this year.

Anadarko encounters natural gas in Mozambique

Anadarko Petroleum’s Barquentine-4 appraisal well proved successful offshore Mozambique, the company said in April. The well in Offshore Area 1 of the Rovuma Basin encountered approximately 525 net ft (160 meters) of natural gas pay and became the Anadarko partnership’s ninth successful well in the complex.

In March, the company achieved oil production at the Caesar/Tonga development in the Green Canyon area of the deepwater Gulf of Mexico. Production from Caesar/Tonga, with an estimated resource base of 200 million to 400 million bbls of oil equivalent, is expected to ramp up to approximately 45,000 boed from the first three subsea wells.

Atwood awarded contract for newbuild jackup

Atwood awarded contract for newbuild jackup

Atwood Oceanics has been awarded a contract by Salamander Energy (Bualuang) for the newbuild jackup Atwood Mako. The award is for a firm duration of 12 months for work offshore Thailand. The rig is under construction with PPL Shipyard in Singapore.

Single bit drills intermediate section of Tattoo field

A single Ulterra polycrystalline diamond compact bit has drilled the entire intermediate section of the Tattoo field in Northwest Canada. An 8.5-in. (216-mm) U513M drilled both the vertical and build sections with the same bottomhole assembly, saving the operator two trips and $570,000 compared with the average of six section offsets in the field in March.

U513M maintains high instantaneous rates of penetration required in the drill-out, as well as the ability to aggressively build angle with tool face control.

Darcy installs downhole sand control system

Darcy Technologies recently completed the first downhole installation of its next-generation sand control system following the success of a robust system integrity test in Aberdeen, which was supported by several global operators and an international oilfield service company.

Darcy’s sand control system was run from a land rig integrating it with standard third-party completion accessories to make up the full sand face completion system. The system was placed on depth and set into a variable wellbore some 1,000 ft below the surface.

Darcy Technologies recently installed its next-generation sand control system about 1,000 ft below the surface.

The system’s construction and high collapse resistance provides a solution for low pressure, shallow and heavy oil reservoirs. The solution can be used in remote or environmentally sensitive locations because gravel pack fluids, pumping equipment, installation and excess personnel are eliminated from the process, and its modular design is integrated with common completion equipment.

The system’s activation by applying pressure from surface eliminates the time, effort and cost of gravel pack completions.

CNPC, Shell sign China’s first shale gas PSC

China National Petroleum Corp (CNPC) and Shell China have signed a production-sharing contract (PSC) for shale gas exploration, development and production in the Fushun-Yongchuan block in the Sichuan Basin.

Subject to government approval, this is the first shale gas PSC signed in China. The contract area covers approximately 3,500 sq km. Shell will apply its technology, expertise and experience.

“We are delighted about this new milestone in our strategic cooperation with CNPC. China has huge shale gas potential, and we are committed to making a contribution in bringing that potential into reality,” Peter Voser, CEO of Royal Dutch Shell, said.

Service diagnoses drilling challenges ahead of time

A new Baker Hughes service identifies potential drilling issues before they occur by pinpointing similar case histories in real time using a global library of drilling practices and expert advice to provide operators with suggestions on how to respond or take corrective actions while drilling.

WellLink Radar Remote Drilling Advisory Service is an integrated solution that uses case-based reasoning and event detection. It leverages Verdande Technology’s DrillEdge software to reduce uncertainty, minimize nonproductive time and increase safety. The service allows for the remote monitoring of multiple wells simultaneously and enhances drilling efficiency.

At-bit inclination technology optimizes well placement

PathFinder, a Schlumberger company, recently introduced the iPZIG at-bit inclination, gamma ray and imaging service. iPZIG helps optimize well placement in target zones through early bed boundary detection.

Developed for unconventional oil and gas markets and high-efficiency drilling applications, the iPZIG service allows for greater directional control and accuracy while drilling versus conventional technologies, with sensors placed directly behind the drill bit. Using data from the iPZIG service, changes in lithology and bottomhole assembly orientation are quickly identified.

ABB to supply vessel with DC-based power grid

ABB recently won an order from ship owner Myklebusthaug Management to supply the first direct-current (DC) power grid onboard a ship. The equipment will allow a new offshore platform support vessel, under construction in Norway, to operate at the highest energy efficiency level to minimize emissions.

The Onboard DC Grid will allow vessels to cut fuel consumption and emissions by up to 20%

The May/June issue of Drilling Contractor featured coverage of the 2012 OTC Spotlight on New Technology Awards. This article can be found in its entirety here.

By Katie Mazerov, contributing editor

Water Rescue Services’ mobile, 24-ft trailers can process 20,000 bbls of water in a 24-hr period using electro-coagulation. From left are produced water, water just after the treatment and the finished product.

As hydraulic fracturing enters a new phase in the current shale boom, the industry has learned a thing or two about the process, not the least of which is that it makes both economic and environmental sense to include the three R’s – reuse, recycle and reclaim – as part of the equation.

It takes three million to five million gallons of water to unlock the hydrocarbons of just one unconventional shale well. That, along with the costs associated with disposal, political pressure, and regulatory changes regarding disposal of fluids, has prompted operators large and small to take a look at their water recycling and reuse strategies.

In response, a variety of technologies have emerged onto the marketplace that allow producers to reuse their water, reduce transportation costs, comply with regulations and reduce their environmental footprint. Last year, Halliburton introduced a comprehensive water management system that meets the full range of customers’ needs, including water supply and storage, transportation, recycling, reuse and disposal. Baker Hughes has two mobile services designed to provide operators with convenient water treatment and drilling waste recycling in unconventional shale formations.

Innovation is coming from many sectors. “The operators themselves have pioneered approaches for water reuse that require a minimum amount of treatment,” said Keith Minnich, water sustainability manager for Calgary-based Talisman Energy. “But water treatment companies are now developing technologies that can accomplish virtually anything – even converting produced water to drinking water. Also, now that the major service companies have developed saline-tolerant additives, it is much easier to reuse produced water,” he said, noting that saline, a product of old sea water embedded in the shale, is no longer considered an operational problem.

Mr Minnich is involved in a joint industry project funded by the governments of Alberta and British Columbia to develop a methodology for the reuse of flowback water. The project is intended to provide operators, service companies and water treatment companies with a framework for evaluating what level of treatment is required for each type of fracturing fluid for a given situation.

“There are different types of hydraulic fracture treatments and different fluids involved in treatments,” he explained. “Some fluids are relatively simple and simple to use; others are more complex and require more treatment.”

The water treatment process for Talisman varies from play to play but has been primarily limited to simple suspended solids removal. The company has been able to reuse flowback and produced water with a minimum amount of treatment in the Marcellus play and the Montney gas field in British Columbia.

“Although the access to fresh water hasn’t been a limiting factor, we are committed to a responsible and sustainable water management strategy,” Mr Minnich said, noting that the Texas drought has caused some concern over the continued availability of fresh water in the Eagle Ford.

How Much Treatment?

Ecosphere Technologies’ Ozonix EF80 Unit works in the Fayetteville Shale. Ozonix is an ozone-based oxidation process that combines ozone, hydrodynamic cavitation, acoustic cavitation and electro-oxidation to destroy bacteria and inhibit scale formation. The EF80s can process up to 80 bbls of frac water per minute

Varying regulatory requirements have posed some difficulties, however. “Where we face some challenges is in the Marcellus play on what to do with the flowback water that cannot be reused. Pennsylvania does not have the same availability of injection wells as Texas, where excess flowback and produced water is commonly injected into deep wells.”

Pennsylvania also has put in place regulations that require water to be treated extensively prior to surface disposal, a costly undertaking. In Canada, surface discharge is not a given, and in Alberta the practice is banned no matter what level of treatment, Mr Minnich noted.

“The challenge everyone is facing right now is determining what level of treatment is actually required for reuse,” he continued. “Unnecessary amounts of treatment raise the cost and make it less attractive to reuse and also generate byproducts. The alignment of what treatment is required and what technologies are available is a work in progress.”

Among the entrepreneurial firms bringing high-tech solutions to the marketplace is Florida-based Ecosphere Technologies, which has developed and commercialized a technology that eliminates the need for oil and gas operators to use chemical biocides and scale inhibitors during hydraulic fracturing operations. Ecosphere’s patented Ozonix technology is an ozone-based, advanced oxidation process that combines ozone, hydro-dynamic cavitation, acoustic cavitation and electro-oxidation into one process to destroy bacteria and inhibit scale formation. Mobile, 53-ft units called Ozonix EF80s can process up to 80 bbls of frac water per minute.

Twelve Ozonix EF10 Units work to treat water at rates of up to 120 bbl/min in the Fayetteville Shale.

Through its subsidiary, Ecosphere Energy Services, the company has treated and recycled nearly 30 million bbls of flowback water, produced water and surface water used as a makeup fluid. The technology can pre-treat raw water needed for hydraulic fracturing operations and post-treat flow-back and produced water at pond sites or fixed facilities, said Ecosphere Technologies chairman and CEO Charles Vinick.

“Typically, the operator brings produced or flowback water to a frac site and stores it in a reclamation pit or frac tanks,” Mr Vinick explained. “A water transfer company will then pump that water to us, along with surface waters from a nearby source.”

The water is blended by a proprietary mixing manifold and then treated with the Ozonix process. Once the water has gone through the system, the effluent water is discharged into a fracturing tank or manifold to be pulled into the pumping service company’s equipment, where it is blended with sand and ready to use as a fracturing fluid.

Ecosphere’s Ozonix technology has been used by Newfield Exploration in the Woodford Play. It can be applied in oil flood operations, enhanced oil recovery and wells producing condensate. The technology also has been deployed in the Fayetteville, Eagle Ford and Permian Basin.

“We are treating water at the flow rate of the frac to eliminate the use of liquid chemicals,” said Robbie Cathey, CEO of Ecosphere Energy Services. “We also believe that by oxidizing organic material and precipitating salt compounds, we are improving the frac fluid’s compatibility with friction reducers, resulting in lower treating pressures.”

Ecosphere’s Ozonix technology has been used by Newfield Exploration in the Woodford play and Southwestern Energy in the Fayetteville over the last three years, and was deployed in the Eagle Ford and Permian Basin this year. The technology, which has been tested or used in all the major plays except the Bakken, can be applied in oil flood operations, enhanced oil recovery and wells producing condensate, Mr Vinick noted. “For operators, elimination of chemicals and recycling of water are key elements of a cost-effective and environmentally safe treatment system.”

An Electrifying Process

ROLCO’s Flow/Pro 20 electro-coagulation system treats and recycles water on a frac pad in Colorado.

ROLCO Energy Services provides water management solutions for unconventional oil and gas producers using an electro-coagulation process that adds an electric charge to the water to convert dissolved solids such as iron, magnesium, calcium and naturally occurring radioactive materials into suspended solids that can be removed with a mechanical filter.

“By changing the polarity of the water, we are allowing dissolved particles to amalgamate and join together and become a suspended solid,” said CEO and founder Perry Roland. The company, founded in 2009, has worked in the Haynesville shale play and the Piceance Basin to treat water for reuse, and plans on entering the Bakken and Eagle Ford oil plays.

“We have figured out the key to do this successfully in the gas market, but the oil side brings some additional challenges, such as the constituents in the water,” Mr Roland said. “As operators continue to move rigs from the dry gas plays to the oil plays, our technology will follow.”

Raw flowback and produced water prior to treatment by ROLCO’s electro-coagulation system (left) is compared with water that has been through the electro-coagulation process (right), prior to the polishing stage, where all remaining solids are removed for more efficient reuse at the fracturing site.

To that end, ROLCO is partnering with AbTech Industries, which has developed the Smart Sponge, an oil-absorbent material that removes hydrocarbons on the front end of the electro-coagulation process so they don’t enter the clean water system.

“The Smart Sponge is oleophilic, so it absorbs hydrocarbons that are in the water, but it is also hydrophobic, so it repels and doesn’t retain water,” said AbTech chief operating officer Jonathan Thatcher. “We manufacture it in a manner that retains very high flow rates through the media and results in little or no pressure loss. It can absorb one to two times its weight in hydrocarbons.”

The process solidifies the hydrocarbons it removes, creating a solid that can be burned as a fuel source in waste-to-energy facilities, cement kilns or incineration operations, Mr Thatcher explained. The water being treated is a combination of fracturing flowback water and produced water. It can be treated repeatedly, although the process may need to be modified because the water profile will change over time.

AbTech’s portable and installed units can process 10,000 bbls/day to 100,000 bbls/day of produced water. Often, there are multiple units on a fracturing site.

A ROLCO electro-coagulation processing site in Colorado treats and recycles 100% of flowback and processed water from fracturing. Contaminated water is collected in a pit, then pumped into electro-coagulation systems, where it is processed on-site and recycled back to the fracturing process.

After the de-oiling process, a number of different technologies, including electro-coagulation, can be used to treat the water for a variety of uses. “The water can be treated to remove everything except brine for reuse in fracturing operations and can also be treated for discharge, which involves further removal of the salts and chlorides, typically by a reverse osmosis (RO) process for discharge into lakes or rivers. Pre-treatment is always required because other technologies, especially RO, can’t tolerate oil and grease coming into their systems,” Mr Thatcher explained.

Because a well will produce up to five times as much water as oil and gas over its life, some in the industry are eyeing water treatment systems as a potential source of water for agricultural purposes, provided all the salts are removed. “We could have a source of agricultural water that is not going to impact traditional drinking water sources such as lakes, rivers and underground aquifers,” Mr Thatcher said.

Reducing Truck Traffic

Electro-coagulation uses electric charge to bond contaminants so they can be dropped into a settling tank. The water is then put through polishing filters before it is returned to the fracturing operation.

Another young company using electro-coagulation, Water Rescue Services Holdings, has been approved by the Texas Railroad Commission to operate a mobile recycling system in the state that allows operators to reuse produced and flowback water. The firm, launched in early 2011 in Fort Worth, is also planning to move into Wyoming, Louisiana and sections of the Marcellus.

Last September, the company signed a strategic alliance with Select Energy Services, an oil and gas services company, to provide a total water management system using Water Rescue’s patent-pending process.

In its mobile, 24-ft trailer, Water Rescue Services can process 600 gallons of water a minute, or 20,000 bbls in a 24-hr period, said Wes Williams, president of Water Rescue Services. “We get a sample of water from the operator with a directive of the water standard they need for their type of fracturing operation, such as slick water, hybrid or crosslink gel fracs,” he said. “We get the heavy metals, such as iron and suspended solids, out easily, but our customers may want other compounds out as well.”

ROLCO and AbTech have developed the Smart Sponge, an oil-absorbent material that removes hydrocarbons on the front end of the electro-coagulation process. At right, Smart Sponge is installed at a fracturing site in Wyoming.

In the electro-coagulation process, the metals surrender as the electric charge is placed on them, and the contaminants in the water bond together and drop into a settling tank. The water is then put through polishing filters before it is returned to the fracturing operation. Solids are compressed, de-watered and removed.

“For every 100 trucks the operator would have to send to a saltwater disposal well, we use three or four, depending on the play,” Mr Williams said. “We return 95% to 98% of the water to the facility, where it can be used again and again. In one play in south Texas, we will be able to keep an estimated 12,000 trucks off the road.”

The company says it has been contacted by government officials wanting to understand the process because they are receiving calls from their constituents about problems on the road.

“The oil and gas industry is going through a shift,” Mr Williams said. “In the past, water was plentiful, cheap and easy. Now water is like gold, and operators need to endorse new technologies to deal with water shortages and achieve high environmental standards. The recycling business is still in an embryonic stage, but companies like ours must prove our reliability to help the industry make recycling more of a necessity than a luxury.”

Ozonix is a registered term of Ecosphere Technologies