Table 1: Input data to compare two kick tolerance calculation methods.

Even though kick tolerance is a critical and fundamental concept for the drilling industry, no standard is used by all operators and drilling contractors. Additionally, the concept is not widely employed or understood to help essential decision-making during drilling. This often leads to discussion during drilling of whether it is safe to continue drilling. As wells are drilled in more challenging environments, it takes only a small variation in kick tolerance calculations to lead to a premature abandonment of the well if a more conservative approach is used or, in other cases, to be against safety when the kick tolerance calculated is higher than what it should be.

To develop a more accurate kick tolerance tool, which would include important effects that are usually not considered in today’s calculations, a review of the state-of-the-art has been carried out. This review showed that what is recommended and in practice in the vast majority of cases is a very simplified and conservative calculation, not taking advantage of even simple spreadsheets to include some important effects.

Table 2: Kick tolerance results of the current industry approach versus the new approach, as well as the error percentages.

Misconceptions on how kick tolerance is calculated were identified. Even though some of them have a small effect on the final result, it is important to have a solid and correct foundation to build on, as the intention is to incorporate other important effects to the final tool. The ultimate goal is to have a tool that can be used by engineers at the office during the well-planning stage, as well as on the rig, to allow a simple and direct evaluation of the safety condition to better define the continuation of operations.

A simplified approach has traditionally employed a single bubble model, and this allows the calculations to be done without any computer help. Although computer power is not a problem and multiphase flow models are available to reproduce gas behavior inside the wellbore, the examples shown here will use the same simplified model the industry has employed for decades, i.e., assuming a single bubble and constant temperature, while ignoring the effects of gas solubility, dispersion and migration.

Table 3: Effect of choke line friction in kick tolerance and line friction-related errors.

The objective is to highlight the misconceptions with a direct comparison, reducing the variables to a minimum.

KICK VOLUME

The first problem identified in the current industry-recommended kick tolerance practice is related to the calculation of kick volume on bottom. The first step is to define the maximum vertical kick height (H_max) at the casing shoe, assumed to be the weakest point in the open hole, based on fracture gradient, mud weight, kick fluid density and predicted pore pressure. The second step is to calculate the kick volume at the casing shoe, V_shoe, from H_max, and then take the volume to bottom (V₁) using Boyle’s Law (Figure 1).

Figure 1: Illustration of kick tolerance calculation for Well A. The current approach requires calculation of Hmax using an adjusted MAASP, Vshoe using annular capacity across the drill pipe, and then take the volume to bottom (V1) using Boyle’s Law. V1 is the same for both kick tolerance approaches, current and new.

The third step, and where the problem lies, is to calculate the kick volume at bottom around the BHA, V₂, and assume as the kick tolerance the smaller of the two volumes between V₁ and V₂. The same H_max is used for calculating V₂, assumed to be at the bottom of the well (Figure 2).

What is conceptually wrong here is that, if the BHA length is greater than H_max the kick cannot be circulated out of the wellbore as it will reach the top of the drill collars with a kick height greater than H_max, which would induce losses at the shoe.

To properly address this point, an extra calculation needs to be done if the BHA length is greater than H_max. Instead of having H_max at bottom and calculating V₂, H_max must be located at the top of the drill collars, calculate the volume across the top of drill collars, V_DC, and then take this volume to the bottom of the wellbore using Boyle’s Law (V₂), in the same way it is done with the kick volume calculated at the casing shoe (Figure 3).

Then select the smaller between V₁ and V₂ as the kick tolerance. If H_max is greater than the BHA length, the difference in annular volume most of the time compensates the expansion of the gas when it travels upwards, reducing the chances of creating a problem.

However, the final tool will take into account all different BHA geometries to reduce to a minimum any simplification in the final result. To keep things as simple as possible here, the BHA in the examples presented has only one diameter, larger than the drill pipe.

Figure 2: Illustration of kick tolerance calculation for Well A using the industry’s current approach. Calculated Hmax is applied to the bottom of the well, and kick volume at bottom around the BHA, V2, is calculated using Hmax and annular capacity at the bottom of the well. The kick tolerance is the smaller of the two volumes between V1 (Figure 1) and V2 (Figure 2).

Two 12 ¼-in. vertical wells are used to compare the two approaches described. Both examples use 0.5-ppg kick intensity above the mud weight, 1.9-ppg influx density, 100-psi choke operator error and 100-psi choke line friction. The other data needed are given in Table 1, and the results are shown in Table 2. As can be seen in those tables, the current approach used by the industry can lead to higher kick tolerance volumes compared with the new approach. These numbers will vary depending on the well geometry and all other variables influencing the kick tolerance calculation.

CHOKE LINE FRICTION LOSS

If the previous misconception can lead to a more risky situation, another leads to a very conservative situation, related to the friction loss generated in the choke line when circulating the kick out of the wellbore. This approach can severely punish the design of the well, especially in deepwater.

When the kick is being circulated, friction loss in the choke line will be generated. As the choke line diameter is often smaller than the wellbore annulus, the friction loss value can cause the pressure inside the wellbore to be very close to inducing a fracture. As a safety measure, it is common practice to deduct the friction loss in the choke line from the maximum allowable annular surface pressure (MAASP).

The result in some cases, for example on a deepwater well, is a very strong reduction in MAASP, leaving the well with a very small kick tolerance, requiring the use of several casing strings. The alternative approach would be to proactively use this friction loss when circulating the kick out of the wellbore, as it makes no difference to the wellbore whether the pressure at the bottom is coming from a choke at surface or from friction generated inside a line or wellbore annulus.

The same wells as described previously will be used as examples, where the only change to be made is the value used for the choke line friction, 100 or 0 psi. Table 3 shows the difference in kick tolerance using the new approach when calculating the kick volume on bottom with BHA in the well, as described previously. The difference in kick tolerance can be dramatic, more than 75% in one case, and with just 100-psi choke line friction. The result can be even more pronounced in a deepwater well, where the choke line is much longer.

Figure 3: Illustration of kick tolerance calculation for Well A using the new approach. If the BHA length is greater than Hmax, the influx must be considered at the top of the drill collars, calculate the volume across the top of drill collars, VDC, using Hmax and annular capacity across the drill collars, and then take this volume to the bottom of the wellbore using Boyle’s Law (V2). The kick tolerance is the smaller of V1 (Figure 1) and V2 (Figure 3).

One might argue that, as the single bubble model leads to very conservative results, in the end there should not be much detrimental effect if some concepts are not properly addressed. Unfortunately, this has been the rationale used in many cases, not just with kick tolerance. But as the magnitude of each simplification and wrong concept is different, one will never know in which direction the final result is moving. When it is well known the conservative nature of the approach, the consequences might be just economical, with the well being over-engineered. However, when the scenario is to increase risk, as it is the case of how the kick volume on bottom is calculated, this is unacceptable. Industry must realize the possible flaws in all the steps when designing and operating a well and quickly correct them.

A simple-to-use and correct kick tolerance tool will allow everyone to have the same basis for evaluation and decision-making. These include decisions to be made not just during drilling but while the well is being planned to help the selection of appropriate tools and methods to safely drill the challenging wells that are more and more common.

Its use before drilling will lead to a safer and more economical casing design, and during drilling it helps define when drilling should be interrupted. Taking advantage of the choke line friction is not as straightforward as properly calculating the kick volume on bottom as it is more difficult for one to proactively use the choke line friction in real time.

This article is based on a presentation at the IADC Well Control Middle East 2010 Conference & Exhibition, 29-30 November, Manama, Bahrain.

Editor’s note: At press time, a federal judge in New Orleans had rejected BOEMRE’s interim final rule on drilling safety. The Department of Interior said the rules remain in effect. In any case, DC has recapped principal elements of the BOEMRE rule, which are likely to affect GOM drilling over the longer term.

While the Gulf of Mexico deepwater drilling moratorium was lifted on 12 October, it remains unclear when drilling in water deep or shallow will return to anything like normal levels. Promulgation of new rules and apparent shortages of necessary inspectors and government personnel have already combined to bottleneck permitting of wells in shallow water. Since the Macondo blowout, just 12 permits to drill new wells have been issued through 14 October for water depths of 500 ft or less. This statistic for the purportedly moratorium-free zone does not bode well for a speedy resumption of drilling in the Gulf of Mexico, irrespective of depth.

The major task now is unraveling and gaining clarification of the 111-page interim Final Drilling Safety Rule, which was posted 7 October in the Federal Register’s reading room in advance of the Department of Interior’s (DOI) move to end the moratorium.

The rule covers wellbore integrity, well control equipment and specifications, and training. Officially issued on 14 October, it became effective immediately. Most of the rule’s provisions were already required under NTLs N05 and N06 issued earlier this year.

26-YEAR BLOWOUT CYCLE

The DOI estimates the rule’s annual implementation cost to industry at $183.1 million. It pegs the cost of a “catastrophic” blowout at $16.3 billion and anticipates such an event will occur once every 26 years, “based on historical trends and the number of expected future wells.”

Despite compelling evidence that blowouts are rare and have historically resulted in minimal pollution and damage, DOI clings to the idea that the Macondo blowout was no rogue event but indicative of a trend. “Circumstances suggest that, while a blowout and spill of this magnitude have not occurred before on the OCS, it is unlikely that the problems are unique to the Deepwater Horizon and BP’s Macondo well,” the regulation reads.

MORE RULES TO COME

This interim drilling safety rule sets the stage for future rulemakings or further evaluations across a number of areas – cementing and casing, fluid displacement, BOPs, secondary control systems and ROVs, wild-well intervention, training, oil-spill response, and organization and safety management.

In particular, says the Bureau of Offshore Energy Management, Regulation and Enforcement (BOEMRE), the regulations were developed “without the benefit of the conclusive findings from the ongoing investigations into the root causes of the explosions and fire on the Deepwater Horizon. In the future, based on the comments we receive on this rule and the additional findings of ongoing investigations, BOEMRE may issue additional regulations or amendments to these regulations that will be intended to further increase the safety of offshore oil and gas operations.”

DEEPWATER TRAINING

While the rule calls for “new requirements for specific well control training to include deepwater operations,” detail is sparse. IADC, whose WellCAP accreditation program is the world’s premier well-control training tool, has determined that the regulation’s call for deepwater well-control training is already addressed in the existing WellCAP supervisory curriculum. Operators and contractors were previously required to determine what type of training is appropriate for their operations; the interim final rule modified that section to include a specific reference to deepwater drilling. Nonetheless, the IADC Well Control Committee will consider at its next meeting possible development of supplemental WellCAP courses dedicated to deepwater.

The rulemaking also means boom times for qualified professional engineers or other “independent third parties,” such as technical classification societies or API-licensed manufacturing, inspection or certification firms. OEMs are specifically excluded. Among the items the third party must certify are:

•  That blind-shear rams can cut any drill pipe under maximum sustained pressure;

•  That subsea BOP is designed for specific equipment on the rig and the specific well design;

•  Certification of two independently tested barriers and that casing & cementing designs are appropriate;

•  Well abandonment design and procedures, including existence of at least two independently tested barriers during abandonment, one of which must be mechanical, and that the plug meets specified requirements.

INCORPORATING API

The new regulations incorporate numerous documents published by the American Petroleum Institute (API). In so doing, BOEMRE has enshrined several Recommended Practices as mandatory. “For API documents incorporated by reference into this part, the terms ‘should’ and ‘shall’ mean ‘must’,” the agency declared.

Highlights of from the new interim final rule include:

CASING & CEMENTING

BOEMRE’s new regulation now requires the operator to include in its Application for Permit to Drill (APD) an evaluation of best practices identified in API RP 65-Part 2, “Isolating Potential Flow Zones During Well Construction.”

“Incorporating this document by reference will help ensure operators use best practices when designing their casing and cementing programs and will help ensure the integrity of the well,” the rule reads.

Operators must include in their write-ups the mechanical barriers and cementing practices to be used for each casing string.

While BOEMRE says API RP 65-Part 2 is an appropriate document for OCS cementing, the agency cautions that additional cementing requirements may be identified through the Macondo investigations.

DIVERTERS & BOPS

BOEMRE now requires submission of a schematic of all BOP control systems — primary, secondary and pods, both for surface and subsea.

Third-party verification is required, as discussed above.

CASING PRESSURE TESTS

Operators are required to perform a pressure test on the casing seal assembly to ensure proper installation of casing or liner in the subsea wellhead or liner hanger. BOEMRE requires this both for intermediate and production casing strings or liner.

Operators must also perform a negative pressure test on all wells.

Procedures and criteria for successful tests must be submitted with the APD.

SUBSEA BOPS

In addition to the requirement that blind-shear rams must be able to shear any drill pipe under maximum anticipated surface pressures, operators must use at least four remote-controlled hydraulically operated BOPs. Each BOP must include an annular preventer, two sets of pipe rams and one set of blind-shear rams.

BOEMRE added requirements for ROV intervention. “The subsea BOP stack must be equipped with ROV intervention capability to operate one set of pipe arms and one set of blind-shear rams, as well as unlatch the LMRP (lower marine riser package). The BOP-ROV interface must allow sufficient volume to actuate all required functions.”

Also, autoshear and deadman-system requirements have been added. All dynamically positioned rigs must have both.

BOP MAINTENANCE, TESTS

BOEMRE now requires the operator to document BOP maintenance and inspections. Maintenance and inspection criteria are unchanged.

As for testing, a new paragraph requires testing of ROV intervention functions on subsea BOP stacks. ROV intervention functions must be tested during the stump test, BOEMRE says, and ensure that hot stabs are function tested and capable of actuating one set of pipe rams and a set of blind-shear rams, as well as unlatching the LMRP.

The operator must also test at least one set of rams during the initial test on the sea floor. The interim final rule will also require function testing during the initial test on the sea floor.

Further, operators must perform full pressure tests when blind-shear or casing-shear rams are used in an emergency. If pipe or casing is sheared during a well-control situation, the operator must retrieve and physically inspect the BOP and conduct a full pressure test of the stack.

FLUID PROGRAM

The BOEMRE district manager must give approval before kill-weight drilling fluid is displaced from the wellbore. The operator must submit with the APD or the Application for Permit to Modify (APM) reasons for displacing the fluid and detail the complete procedure.

This must address:

•  Number and type of independent barriers in each flow path;

•  Tests to ensure the barriers’ integrity;

•  BOP procedures used while displacing kill-weight fluids;

•  Procedures to monitor fluids entering or leaving the wellbore.

European Commission urges its own moratoria; industry fights against ‘unjustified’ move

Even as the deepwater drilling moratorium is lifted in the US, the European Commission urged member states to consider suspending licensing of “new complex oil or gas exploration operations” until European offshore safety regimes are assessed.

“While any decision to suspend offshore drilling operations is left to the discretion of Member States, the commission reiterates its call upon the Member States to rigorously apply a precautionary approach in the licensing of new complex oil or gas exploration operations and to examine whether a suspension of such licensing is needed until the European offshore safety regimes have been assessed in light of the Deepwater Horizon accident,” the commission proclaimed.

The announcement brought a speedy and blistering response from Oil & Gas UK, whose chief executive Malcolm Webb said, “Oil & Gas UK is extremely concerned that, once again, the EU Commission is calling for a suspension of new licensing, a measure that is wholly unjustified and inappropriate for the UK offshore oil and gas industry. It is also deeply worrying that in addition, it now proposes to implement centralized and prescriptive safety regulation.”

The result will be counterproductive, Mr Webb contended. “This would undermine the advanced and highly sophisticated regulatory regimes currently working so well, for example in the United Kingdom, Norway and the Netherlands,” he said.

Mr Webb pointed out that the UK’s Oil Spill Prevention and Response Advisory Group (OSPRAG), a coalition of industry, regulators and trade unions, clearly demonstrates the “responsiveness of the safety-case regime and the open safety culture which it breeds.”

OSPRAG, which kicked off operations in May, recently announced plans to move ahead with commissioning detailed designs for a full/partial pressure-capping device with the potential to serve as a central element of the UK’s oil-spill response contingency plans. The engineering firm Wood Group Kenny developed the system, developing three design concepts. Of these, OSPRAG opted to progress with a modular device to close off a well in the event of a blowout. OSPRAG said that this design is the most appropriate for the weather typical of the UK, particularly West of Shetland.

In the US, five major operators have committed $1 billion to developing the Marine Well Containment System. The operators, Chevron, ConocoPhillips, ExxonMobil, Shell and BP, plan specially designed equipment available for rapid response and capable of operating in water depths to 10,000 ft. This will add containment capability of 100,000 bbl/day, significantly more than the Macondo spill.

IADC met with representatives from the Washington, DC, OSHA Directorate of Enforcement Programs on 16 August to seek clarification on the Enforcement Policy for Flame-Resistant Clothing (FRC) in Oil and Gas Drilling, Well Servicing and Production-Related Operations, issued on 19 March 2010. API, AESC, IPAA and the Mid-Continent STEPS and Permian STEPs Network were also present at the meeting.

The associations, concerned that OSHA bypassed the rulemaking process in announcing the policy, asked the agency to withdraw the policy announcement. Richard Fairfax, director of the Directorate of Enforcement Programs, declined the request but promised to discuss industry’s concerns with Dr David Michaels, assistant secretary of labor for occupational safety and health. OSHA expressed concern that the normal rulemaking process will take too long to address this issue. Industry sought a time frame for receiving a response to its concerns, but none was given. IADC is reviewing additional steps to address this issue.

STCW 2009 Convention and code

An IMO Conference of Parties, held in June 2010 in Manila, adopted major revisions to the International Convention on Standards of Training, Certification and Watchkeeping for Seafarers (STCW Convention) and its associated Code.  Known as the “Manila Amendments,” it enters into force on 1 January 2012. It includes: improved measures to reduce fraudulent certificates; revised requirements on rest hours; new training requirements for modern technology; additional training requirements on marine environmental awareness; leadership and teamwork; updated competency requirements for tanker personnel; new security training requirements regarding piracy, introduction of new training methodologies; and training guidance for personnel operating in polar waters and personnel operating dynamic positioning systems.

Scrapping/transferring of vessels

The transfer of a US vessel to another registry or to a non-US citizen requires MARAD (Maritime Administration) approval under current regulations. Recently, MARAD advised that it and the Environmental Protection Agency (EPA) are negotiating a Memorandum of Understanding governing EPA’s review of any proposed transfers of ownership of US-flagged vessels, including those being sold for scrap to foreign buyers. Details of this MOU are not available, but MARAD is already applying requirements on an ad hoc basis and will likely be updating its regulations.

12 Years – November/December 1998

New Drilling Services Division a home for technology

IADC has launched a new Drilling Services Division and organized an Underbalanced Operations Committee as its first task group. The new division is designed to serve as a home for technical service firms to pursue political, regulatory, marketing and business development opportunities. The division targets both conventional and emerging drilling technologies, such as coiled tubing, directional drilling and more.

Ken LeSuer, vice chairman of Halliburton Company, was elected vice president of the Drilling Services Division.

The IADC Underbalanced Operations Committee will encompass the work and membership of the International Underbalanced Operations Forum, which will disband. The new IADC group will be chaired by Dr Paul Francis, research and technical services for Shell International Exploration and Production. It will comprise three work groups – Training, chaired by Don Hannegan, Williams Tool; Standards and Nomenclature, chaired by Noel Monjure, ABB Vetco Gray; and Daily Report, chaired by Dag Oluf Nessa, Smedvig.

IADC plans to hold a conference on underbalanced operations in fall 1999 in Europe.

22/23 Years – December 1987/January 1988

Innovative drilling program leads to new casing record

What is believed to be the longest and heaviest 13 ^3/8-in. casing string ever set in the North Sea was recently run by the Galveston Key, a sophisticated jackup rig owned and operated by IADC member Santa Fe International Corp.

According to operations manager JB Westlake, the feat was accomplished while drilling for Fina Petroleum Development Ltd in Block 49 of the British Sector. The casing string, successfully set and landed at 10,862 ft, had a dry weight of 792,000 lbs.

Fina’s innovative drilling program, says Santa Fe, was the driving force behind the new record. The program called for driving a 20-in. conductor to a depth of 440 ft below seabed, followed by a 12 ¼-in. pilot hole drilled through a diverter to 3,537 ft and reamed to 26 in. A 20-in. casing string was then set and cemented at 3,506 ft.

Although most North Sea operators customarily drill 17 ½-in. hole, Fina opted for a novel approach: a 16-in. wellbore to 10,912 ft using 6,500 ft of 6 ^5/8-in. OD drill pipe. “The reduced hole size and the larger-than-normal drill pipe,” Santa Fe discloses, “assisted us in maintaining excellent hydraulics while drilling this long hole section.”

A 12 ¼-in. hole was then drilled to the top of a normally troublesome salt section, which was successfully underreamed to 15 in. from top to bottom and cased with 10 ¾-in. P110 (109 lb/ft) string. Below the salt, Santa Fe set a 9 ^5/8-in. casing string.

The Galveston Key, used for the record-breaking job, was built in 1978 by Marathon LeTourneau at its Brownsville, Texas, shipyard.

31 Years – August 1979

Demand soars for submersible barges

Foreseeing a new flurry of drilling activity in shallow-water prospects, drilling contractors are beefing up their fleets of submersible units.

One of the latest additions is Circle Bar Drilling Co’s AP Merkel, rebuilt from a hull that had been out of service for several years, during the slump preceding the present boom in shallow-water drilling.

The AP Merkel, named after Circle Bar’s vice president of operations, can drill in up to 30 ft of water and has been equipped with new, more powerful drilling equipment.

The diesel electric rig, rated to drill to 20,000 ft, says IADC member Circle Bar, is equipped with the latest in blowout prevention and well control systems.

The barge carries its own well-logging and cementing units, as well as dry bulk material-handling facilities.

Patrick F Taylor, president of Circle Bar, says the “new” submersible rig will work off the Southwest Pass of the Mississippi River for Hunt Energy Corp.

At least two other IADC member companies are also adding to their submersible rig fleets.

Transworld Drilling Co, a subsidiary of Kerr-McGee, is putting the finishing touches to its Rig 65, a new submersible device with the capability of drilling in 70-ft water depths.

At the same time, Transworld says construction is well under way for its Rig 68, a submersible barge with a water-depth rating of 100 ft, quite unusual for this type of rig.

Santa Fe Drilling Co, a subsidiary of Santa Fe International Co, has converted its Blue Water 2 semi into a submersible unit. The conversion was made at Baker Marine’s shipyard located at Ingleside, Texas.

40 Years – September/October 1970

Rowan International rig completes record move

Rowan International’s propulsion-assisted jackup rig located offshore Nicaragua recently completed a record-breaking field move of 74 miles, with speeds up to 7 mph, utilizing two Tidex work boats. The total elapsed time from release to commencement of operations on the new location was 15 ¼ hours.

Chevron’s well, Toro Cay #1, is the third well spud in 3 ½ months since the Rowan Houston arrived in Nicaragua after a 10 ½-day tow from Belle Chasse, La., in which speeds up to 6 mph were obtained using only a single 3,600-hp tug.

The specially designed kort nozzle thrusters are chain-driven by 750-hp DC motors. Four 1,100-hp diesel engines, normally used for powering the drilling equipment, provide the power required by the thrusters.

A second unit, the Rowan New Orleans, essentially identical to the Rowan Houston, is under construction at LeTourneau’s Vicksburg facility; delivery is expected this month. Each unit is 168 ft by 203 ft and is designed to operate in water depths up to 200 ft.

61 Years – December 1949

Drilling at highest peak for this year

Drilling in oilfields of the United States and Canada hit a new high for the year during the week of December 5, according to reports received by A.A.O.D.C. from Hughes Tool Co. The total for the week of 2,253 active units compares with 2,227 a week ago, 2,106 a month ago and with 2,436 rigs reported operating for the same period in 1948.

Increased interest in the West Texas and New Mexico area boosted the drilling there to 699 active rigs, up 32; Oklahoma-Kansas with 401, was up 24; Illinois 151, up 6; Arkansas-Louisiana-Texas, 161, up 2. Reduced activity was reported in three areas: Gulf Coast, 517, down 24; Rock Mountain and Canada, 183, down 9; and Pacific Coast, 141, down 5.

Corby Jones (left) and Dustin Husser (right) were recruited into Pride under the company’s Management Training Program (MTP). As a management training specialist, Rachel Buerker helps MTPs like Mr Husser and Mr Jones to get as much training as they can.

Contrary to what some industry veterans are worried about, young professionals today are not afraid of hard work. They know what will be required in order to succeed, and they are prepared to do what it takes, said James “Corby” Jones, operations engineer for Pride International’s Deep Ocean Ascension drillship.

Mr Jones is one such young professional. He graduated from Texas A&M University in 2008 with a petroleum engineering degree and joined Pride the same year under the company’s Management Training Program (MTP). MTP is designed around an accelerated training regimen to expose the employee to all aspects of the company, enhance industry knowledge and teach participants management skills. The participant is placed in a managerial role upon completion of the program.

“The single most important thing is to have a strong work ethic and be willing to accept every opportunity and challenge that is thrown our way,” Mr Jones said.

New and inexperienced workers also value their time with industry veterans – whom they see as a valuable learning source. The challenge is often getting the veterans to trust a new and inexperienced hire, said Rachel Buerker, management training specialist for Pride. That’s a common hurdle she sees in her job, which includes assisting the MTPs in getting as much experience and training as they can.

Dustin Husser is another recent recruit under Pride’s MTP, which he started in 2007 after graduating from Louisiana State University with a mechanical engineering degree. In just three years, his assignments have taken him around the world to Brazil, Mexico, India, Angola, Chad, South Africa and France. He is now operations engineer for Pride’s drillships in South Korea. According to Mr Husser, his challenge is having to reprove himself everytime he walks on a rig and there is a fleet of experienced hands. “They’ll test you and they’ll doubt you,” he said.

To get over that challenge, he learned, you just have to roll up your sleeves and work as a cooperative group. “When they realize you’re there to help them, they will teach you and work right along with you. Once they see you working hard, they are more willing to teach you what they have learned through their mistakes so we don’t make the same mistakes again.”

Aside from the MTP, Pride has also been using individual development plans and mentor programs for employee development. Individual development plans help workers define goals, map out ways to reach those goals and identify potential barriers. Mentor programs provide new employees with a connection to experienced veterans, said Ms Buerker, who holds degrees in psychology and managerial studies from Rice University.

As a young professional herself who joined Pride in 2006, she also encourages recent hires to ask as many questions as they can: “Those guys out there know a lot. If you don’t ask, you’re not going to find out. And if somebody is not willing to teach you, don’t be afraid to go to the next person to find the answers you need.”

From the other side, she also urges management to make time to meet with and engage its newhires. “Go face to face with them. It helps them to know and believe in the executives’ mission, vision and values if they have actually said it to you, not just in e-mails. You can send all the e-mails you want, but if you can meet them and talk to them, it’s much more credible.”

Maggie Cox contributed to this article.

Click below to see a video interview with Dustin Husser, Corby Jones and Rachel Buerker.

Click here to view the embedded video.

The UK has seen 55 E&A well starts in 2010 as of late September. Hannon Westwood expects 10 to 15 more wells to start by the end of the year.

As of late September, there had been 55 exploration & appraisal (E&A) well starts on the UK Continental Shelf (UKCS) in 2010, including 41 spuds and 14 sidetracks, according to UK-based research firm Hannon Westwood. That’s compared with a total of 76 E&A well starts in 2009, with 40 spuds and 36 sidetracks. “Already in terms of spuds we’ve exceeded the 2009 levels, and we’ve still got a quarter of the year to go,” said Simon Robertshaw, Hannon Westwood senior intelligence analyst. He expects an additional 10 to 15 wells to start before year-end.

For 2011, Mr Robertshaw expects activity levels to stay broadly in line with 2010, although only 24 wells were actually planned for 2011 as of late September. One difference could be that there might be more exploratory drilling versus appraisal drilling next year. Considering a minimum of 50 spuds in 2011, 30-plus will likely be exploration and 20-plus will be appraisal, he said.

On the rig side, there were 24-25 mobile drilling units operating in the UK sector of the North Sea in late September, 13-16 of which were on E&A wells and nine on development wells. In Northwest Europe, the September snapshot showed 38 semisubmersibles active, representing a 90% utilization rate, and 36 active jackups for an 80% utilization rate.

Highlights from UKCS Q3 2011 drilling activities.

Those numbers are projected to stay relatively stable through 2011, although there is potential for both segments to grow. “The word out there suggests that the jackup market will actually improve and demand should grow next year. It’s already starting to grow in the UK. I believe the same could be said for semisubs,” Mr Robertshaw said. He also points out that, although jackup dayrates are “way, way down” from their 2008 peaks, drilling in the southern UKCS gas basin is still at a historically low level. That betrays a negative perception of the future direction of natural gas prices. “If you’re concerned about the outlook for the gas price, you might hold off drilling … despite the fact that you can pick up a rig pretty darn cheaply,” he said. Of the 55 E&A well starts as of September, 25% of those were in the gas basin.

Exploration, appraisal and development wells are projected to take up roughly equal percentages of the UKCS drilling market through 2015.

The Northern North Sea made up about 15% of those 55 well starts. In this sector, Mr Robertshaw believes that the recent success of the Cladhan sidetrack well – which was an upper Jurassic discovery rather than the middle Jurassic sands more typical of the area – could lead to more exploration nearby. “The discovery has helped to de-risk some of the other activities out there. We could see further drilling on the back of that,” he said.

In the Central North Sea, Nexen Petroleum’s Golden Eagle area and Buzzard discovery will no doubt trigger more drilling in the near term. “Nexen just placed its fourth platform in place on Buzzard. Put that in the UK context. People building four platforms for a field? When did that last happen? The ’70s? … Certainly we’ll see additional activity on the back of Nexen’s success.”

The rest of this year’s well starts have been in either the East Irish Sea area (four wells) or the West of Shetland/Atlantic Margin area (three wells).

“West of Shetland/Atlantic Margin had a slow start, but now a multiwell program is kicking up in there… That particular sector will increase,” Mr Robertshaw said. In his lookahead to 2015, which currently stands at 175 actual planned wells, approximately 10% of them will be in this sector. Because the area still lacks infrastructure and most drilling lies in deepwater, “it has to reach a critical mass … in order to get a sufficient number of discoveries appraised to say that, yes, we can commercialize these,” he said.

Although the Central North Sea will continue to dominate UKCS drilling, the exploration-driven West of Shetland sector is expected to be a significant growth area over the next five years.

The Stena Carron drillship recently moved to the West of Shetland to start what could be a three-well program for Chevron, starting with the Lagavulin prospect. Despite some initial challenges – it was reported in September that Greenpeace activists tried to prevent the vessel from reaching the wellsite by attaching themselves to the anchor and swimming nearby – the Lagavulin well has been spud.

The drillship could also later drill an appraisal well for an existing discovery or drill another exploration prospect for BP. “In the near term, we’re looking at at least four wells in deepwaters off the West of Shetland area,” Mr Robertshaw said.

On the investment side, he believes 2010 will end up with approximately $1 billion put into E&A wells; 2011 could see up to $1.2 billion invested. “There is potential for 2011 to see more investment, provided we can get the funding,” he said. Especially for the lower-tier companies that are exploration-led, they may still struggle to raise cash. Approximately 40% to 45% of Hannon Westwood’s forecasted UKCS E&A wells to 2015 are still underfunded. “We understand there is some private equity funding out there, but it’s difficult.”

The horizontal gravel-packed wells on BC-10 Phase 1 include premium sand-control screens, a ball valve-type fluid loss device and permanent downhole pressure and temperature gauge for production and reservoir management.

Applying completion technology to a well for optimal production is never simple, even if the plan calls for only “basic” temperature and/or pressure sensors. Designing and installing a completion system requires an enormous amount of planning to account for a seemingly infinite number of variables, even when developing a field with multiple similar wells.

Most multi-well fields are similarly completed. However, even in the same field, various subsurface features such as faults, dips and multiple reservoirs can mean that some wells require different completion systems for optimal life and production.

Not that long ago, the industry was completing wells with little or no downhole communications systems, no temperature- and pressure-sensing systems, and no way to choke off a zone that was producing too much water. The smart well technology that the industry relies on today, even for the “simplest” of completions, wasn’t developed yet.

Even with state-of-the art downhole communication systems, sliding sleeves for closing and opening various formations, real-time data transmission, fiber optics, and sensors and gauges for every conceivable purpose, operators still strive to keep completions as simple as possible, with only the right level of intelligence necessary to manage an optimally producing field.

There is no need to go overboard with the technology just because it’s available, as complexity increases well construction costs and reliability risks.

Operators are constantly looking for ways to make completions simpler, less costly and more reliable. That includes taking equipment typically installed downhole, such as electrical submersible pumps (ESPs), and moving them to the seafloor or higher.

Two such field developments are Shell’s Parque das Conchas, also known as BC-10, offshore Brazil, and Murphy E&P’s Azurite field offshore the Republic of Congo.

OPEN-HOLE GRAVEL PACKS, ESP BOOSTING SYSTEMS

The goals for the deepwater, shallow-depth, heavy oil BC-10 wells, with highly faulted reservoirs just above or adjacent to subsurface salt domes, were three-fold. First, they had to produce at high rates. Second, they had to be completed in a way to minimize interventions. Third, the wells had to contact as much of the reservoir as possible to produce for 20 years or longer.

“Because of the faulted nature of the BC-10 Phase 1 Ostra field, the long 1,000 m-plus horizontal open-hole gravel-pack wells were not only required to deliver high production rates, they enabled production from the different fault blocks,” said Wouter Bode, Shell’s BC-10 lead completions engineer in Brazil, “especially since it was unknown in the planning phase whether these faults identifiable on the seismic would allow for communication.”

Phase 1 of the field development included nine horizontal producing wells, one deviated producing well and one vertical injector well. Phase 2 completions will be similar, Mr Bode said. “We are looking at seven more producers and four water injectors to develop an additional field located to the north, named Argonauta O-North. The producers will again be horizontal gravel-packed wells executed similar to the successful low-skin Phase 1 wells.”

Shell announced the launch of Phase 2 in mid-October 2010; the drilling and completions campaign is expected to be executed in 2012 and 2013.

The horizontal gravel-packed wells will include premium sand-control screens, a ball valve-type fluid loss device and permanent downhole pressure and temperature gauge for production and reservoir management. The pressure and temperature gauge will measure data to indicate downhole conditions, allowing Shell to anticipate changes in the well and reservoir and to minimize potential adverse events that could affect production rates or longevity. Data from each well are displayed and stored in Shell’s real-time operations centers onshore during the entire life of the field.

For BC-10, Shell moved the ESP to a manifold on the seabed. This allowed Shell to boost pressure at the mudline and push the separated oil to the FPSO Espirito Santo.

A major conceptual design decision taken for Phases 1 and 2 was to move the ESP from its typical downhole location to a manifold on the seabed, allowing Shell to boost pressure at the mudline and push the separated oil to the floating production, storage and offloading (FPSO) vessel. This eliminates the challenge and possible damage to the wells’ inflow system during change-out or workover operations on the ESPs. The boosting system also includes a caisson fluid separation system, as well as the ESP, so it is not as “simple” as installing an ESP onto a manifold.

A separate 100-m deep well was drilled for installation of the modular boosting and separation system. Full-scale onshore testing of the system was conducted for several years before it was implemented on the BC-10 field. It consists of a 100-m long caisson, which acts as a cylindrical cyclonic gas-liquid separator installed vertically in the shallow well, and a 1,500-hp ESP housed inside the caisson.

The oil enters the caisson through a top end assembly and flows into the separator through an angled tangential inlet spool. The liquid and gas separate as the flow stream travels downward 100 m in a spiral pattern, with additional separation occurring by centrifugal force. The liquid then flows down to the caisson sump, where it is pumped back upward by the 1,500-hp ESP into oil flowlines to the FPSO.

During Phase 1 development, four modular boosting systems were installed on one manifold and two on a second manifold. The plan for Phase 2 is to install an additional four modular boosting systems.

BC-10 CHALLENGES

“The main challenges in Brazil,” Mr Bode said, “is to achieve the productivity in deepwater from low-temperature medium- to heavy-oil fields, such as Ostra (24º API) and Argonauta B-West and O-North (17º API), that are hydrostatically pressurized and in a shallow-below-mudline setting with low available frac gradient.

“This makes delivery of high-rate wells in comparison to, for example, deep, warmer and geopressurized wells challenging. This type of well in the Gulf of Mexico has many challenges themselves, such as the casing design, number of casing strings required, depth, high temperatures, unconsolidated nature of the reservoirs and, not the least, compaction.

“So for BC-10, two enablers are drilling and completing very long horizontals and developing and working out the modular boosting systems for pressure boosting and separation,” Mr Bode continued. “It is no longer new technology for BC-10 Phase 2, however. To get them done right the first time requires a lot of detailed planning and careful execution.”

Another enabling technology is rotary steerable systems for drilling the reservoir section of the wells. “Rotary steerable systems provide a smooth wellbore, facilitating running of the sand-control screens and placement of the gravel pack in these long horizontals, the longest of which was 1,160 m,” Mr Bode explained.

He also noted that, without rotary steerable capability holding angle in the horizontal sections, they might not have been possible due to the unconsolidated nature of the BC-10 wells and the need to clean the hole continuously to manage ECDs below the frac gradient.

Looking toward Phase 2 development, Mr Bode noted that Shell will continue with similar technology and completions used during Phase 1. “However, what we did in BC-10 Phase 1 and what we will do in Phase 2, including the ESP systems, remains challenging.

“It is also clear that we are not planning a lot of smart well technology with distributed temperature systems or other gadgets,” he continued. “It does not provide value for money on BC-10 Phase 2 and would just add unnecessary complexity to what we need to achieve.”

Murphy’s Azurite field produces from multiple zones and fault blocks at different reservoir pressures to the industry’s first FDPSO. It includes four producing wells and two water injection wells. Four additional wells should be completed by the end of Q1 2011.

MURPHY’S AZURITE FIELD

Murphy’s Azurite field offshore the Republic of Congo produces from multiple zones and fault blocks at different reservoir pressures to the industry’s first floating drilling, production, storage and offloading (FDPSO) vessel. The field presently includes four producing wells and two water-injection wells. Four additional wells – two producers and two injectors – are planned. The remaining wells, being drilled by a Nabors rig installed on the FDPSO, are scheduled to be completed by the end of Q1 2011.

Some of the completion technology employed in the Azurite wells includes vertical tree slim-bore (13.4-in. OD) hanger and wellhead systems; single-trip perforation and frac-pack systems; downhole pressure and temperature sensors; and dual choking smart valve systems. The smart valve system allows Murphy to commingle oil in the wellbore from two reservoirs, both producing, and to control the reservoirs individually. Presently, the smart valve systems are installed in two producers and one injector. One of the remaining injector wells yet to be drilled will contain a smart valve system.

The wells also contain sensors to measure temperature and pressure above and below the smart valves, with a triple gauge pack, one for each of the reservoirs and one for the commingled production. Each gauge pack consists of three pressure and three temperature sensors.

“This technology has been used previously, so it is not new,” said Brian Joslin, staff completion engineer for Murphy. The use of the slim-bore system on the Azurite project is new, and it is another step forward for completions, as it required making the subsea completions compatible with the smaller-ID marine risers by decreasing the completions’ running diameters.

“There are the standard gauges on the annulus and production side of the tree upstream and downstream of the chokes,” explained Jeremy Lochte, staff consultant for Deep Sea Development Services and subsea adviser to Murphy. “We have acoustic sand detectors on the producers and a flow meter at the choke in the injector wells because we have a common supply to all of the injection wells, and the flow meters indicate the amount of water injected into the different wells.”

DOWNHOLE INTELLIGENCE

The goal for the Azurite wells was to design the completions to avoid interventions or workover operations. That took into consideration that the rig on the FDPSO would be removed after the final well was drilled and completed.

That is also the reason Murphy installed downhole sleeves and valves for choking off individual reservoirs, as well as surface-control capabilities for every function of the field.

Murphy believes it has just the right level of intelligence in its Azurite producers and injectors. The company is using smart well systems to adjust the flow from the producers and the flow into the injectors to balance the water flood.

“Reliability of the equipment is very important,” said Scott Bennett, Murphy’s completions team leader. “We are not using any new technology in our downhole equipment; we wanted to use systems that are going to work.”

Among the completion technologies employed in Murphy’s Azurite wells are vertical tree slim-bore hanger and wellhead systems; single-trip perforation and frac-pack systems; downhole pressure and temperature sensors; and dual choking smart valve systems. The smart valve system allows Murphy to commingle oil in the wellbore from two different reservoirs, both of which are producing, and to control the reservoirs individually.

“Reliability (of selective well completions) historically has been low,” Mr Lochte said. “I would say around 50%. It’s still a risk/reward, where you spend money upfront, and, if it works and the valves remain functional, you save yourself a workover.”

“When you get into subsea wells, the cost is so high that it is more economical to run a smart system,” Mr Joslin added.

On the other hand, companies touting light riserless intervention systems that can perform workovers and other downhole functions without using an expensive semisubmersible could influence the completions market. Vessels with light intervention equipment could be used to open and close downhole valves, competing to some degree with smart well systems by reducing operators’ costs to perform a workover at a later date. This would allow operators to forgo smart well costs upfront.

Some operators will be more willing to use light intervention systems more frequently as confidence builds. “My philosophy is that the second mouse gets the cheese,” Mr Lochte said. “It’s so much better to be the second to do something because they benefit from all of the lessons learned.”

“That’s an open question in the industry,” Mr Joslin said. “Can we reduce our costs by reducing the complexity of smart well completions based on light intervention systems?

“The industry is going to see two markets,” he continued. “It is going to see complex completions become more reliable, and costs will drop as more companies compete in that market. The other market is for light intervention systems that will find a market for unforeseen workovers.

“There will be an increasing number of subsea wells, more unforeseen workovers will be required, and there will be a drive to locate the least expensive method to perform that intervention,” Mr Joslin added. “As that market grows, costs will fall as well.

“Meantime, the industry will continue to install smart completions to avoid interventions in the future, resulting in a double push for technology.”

When asked if there is any technology available today that wasn’t available in 2009 when the initial Azurite wells were being drilled, Mr Joslin said, “I think everyone wants more information, better information and more reliable information, and that could come from fiber-optic technology downhole. For example, I want real-time data from downhole gauges while I’m fracking a well.

“I know companies are working on such systems. I don’t think the technology development is stagnant,” he continued. “The industry is going to see incremental changes over the next several years. And cost-wise, fiber-optic technology is going through the same iterations that smart wells and valves have gone through.”

Despite technologies that are under development, the conversation always turns to reliability, which perhaps tops the industry’s wish list. “We use a lot of technology in these wells,” Mr Joslin emphasized.

“None of it is brand new; it’s all been used in some way, but a lot of the technology is not commonly used, and sometimes the technology is not commonly used in conjunction with other technology.

“Look at the technologies comprising a single-trip system, where you perforate, frac pack and then trip out of the hole,” he continued, “and you combine that with smart valve systems, slim-bore systems, pressure and temperature sensors and gauges and so on to provide the ability to see above and below the smart valves. There are not a lot of those systems around the industry where all of that technology is combined.

“What we want is reliability,” Mr Joslin concluded. “We want what we have to work.”

The MFrac software helps to simulate hydraulic fracturing solutions using 3D geometry.

Baker Hughes has been awarded an eight-year contract extension from Repsol for the supply and maintenance of electrical submersible pumping (ESP) systems in Ecuador’s Block 16 and Tivacuna production areas. The contract covers 200 wells in which ESP systems are needed to maximize production. The latest Centrilift SP Superior Performance ESP system, featuring an extreme-duty pump design, will be deployed.

Separately, BJ Services, a Baker Hughes company, has been awarded a contract by Woodside Petroleum to provide casing and tubing running services in Australia. Work associated with the three-year contract began in May 2010 on various wells offshore northwestern Australia. A suite of casing and tubular handling equipment, including flush-mounted spiders and the fill and circulate tool, will be used to carry out this contract. Diamond Offshore’s Ocean America semi has been fitted with the BJ Services Derrickman system, which includes a remotely operated mechanical arm that makes it possible to maneuver tubulars and drill pipe into a vertical position without the need for a crew member to act as a traditional stabber.

Further, Baker Hughes has acquired software developer Meyer & Associates to enhance its capabilities to design hydraulic fracturing simulation plans for unconventional gas, tight formations in the deepwater Gulf of Mexico and carbonates in the Middle East. Meyer & Associates’ MFrac software, which includes 3D fracture geometry and integrated acid fracturing solutions, will be integrated into Baker Hughes’ Reservoir Development Services.

NDC gives 3-year contract to Derrick Services

Derrick Services has been awarded a three-year fleet inspection and recertification deal by Abu Dhabi’s National Drilling Co covering nearly 30 rigs in the Middle East. The company recently also won a similar contract for ENAFOR in Algeria for the inspection and recertification of their land drilling rigs.

GE Oil & Gas’ litho density tool helps to distinguish oil from gas in reservoirs.

GE, Allied Wirelines to partner on wireline logging

GE Oil & Gas and Allied Wireline Services have signed a long-term partnership agreement on wireline logging. Allied will purchase a broad range of logging tools and related equipment from GE, and the companies will cooperate in the development of GE’s Open-Hole Ultrawire Formation Evaluation tool suite. GE will provide Allied with technical and services support from facilities in the US, Canada and the UK.

Knight Oil Tools buys Advanced Safety

Knight Oil Tools has acquired Advanced Safety, which specializes in custom safety and training programs.  The company offers facility and job site inspections, safety consulting and planning, and training and certification programs. Trainers are certified in areas such as fall protection and vertical rescue, equipment operator certification, forklift certification, OSHA compliance training, DOT consulting, training through NCCER and assistance with ISNetworld. Michael Pothier has been appointed vice president/general manager of Advanced Safety.

Mustang to design topsides for Chevron’s Jack, St. Malo

Chevron has selected Mustang, a Wood Group company, to perform detail design for topside facilities for the Jack and St. Malo floating semisubmersible facility, to be located in approximately 7,000 ft of water in the Walker Ridge Area of the Gulf of Mexico. Mustang, which also designed Chevron’s Blind Faith platform in the Gulf, will provide detailed engineering for integrated control and safety systems under its International Master Agreement with Chevron. The agreement appoints Mustang as a main automation contractor for Chevron’s Global Upstream business units.

Regalado rejoins Cudd

Todd Regalado has rejoined Cudd Energy Services as vice president of corporate services. Since 1989, Mr Regalado has led well control operations in 42 countries, including the Al-Awda project in Kuwait in 1991. In 1998, he was the first well control team leader to control a blowout in deepwater through vertical intervention.

K&B to help Alcoa assemble aluminum alloy drill pipes

Alcoa Oil & Gas has retained the services of K&B Machine Works to assemble its aluminum alloy drill pipes by installing a machining cell for threading aluminum alloy tube, a dedicated steel tool joint threading unit and a new semi-automated Super-Shrink Grip assembly unit for steel tool joint installation.

UniversalPegasus opens Marcellus Shale office

UniversalPegasus International held an open house in late August 2010 for its new Marcellus Shale office in Canonsburg, Penn. Company CEO John Jameson and Moe Barnes, the Onshore Division chief operating officer, welcomed guests, including representatives from many Marcellus Shale development companies.

Swire acquires Gator Tank

Swire Oilfield Services has acquired Gator Tank Rentals, which provides tank, container, basket and mud skip rentals throughout the Gulf of Mexico. London-based Swire supplies specialty offshore cargo carrying units.

Jeter joins American Augers

Greg Jeter has joined American Augers as international territory manager, responsible for the Middle East, India, Afghanistan, Georgia, Kazakhstan, Kyrgyzstan, Pakistan, Tajikistan, Turkmenistan and Uzbekistan.

Schaffer is new senior research director for forecasting firm

Nathan Schaffer has joined analysis and forecasting firm Groppe, Long & Littell as senior research director. He was most recently director in the Houston office of PFC Energy.

Crowley appointed new president, CEO for Enventure

Enventure Global Technology has appointed David Crowley as president and CEO. He joins the company from Precision Drilling Oilfield Services following its acquisition of Grey Wolf Drilling, where he led the US and international divisions. He succeeds Ray Ballatyne, who announced his retirement earlier this year.

PRODUCTS

SeaLance, RipTide technologies introduced

Weatherford International has launched SeaLance, a subsea drilling-with-casing (DwC) system, and the RipTide drilling reamer. The DwC system makes it possible for a 20-in. casing string and its high-pressure wellhead housing to be drilled to depth, cemented and released in a single run. It was jointly developed by Weatherford and ENI.

The RipTide drilling reamer enables operators to enlarge holes up to 25% beyond bit diameter during hole-enlargement-while-drilling operations. The RipTide RFID model is the industry’s first electronically controlled drilling reamer that allows operators to activate and deactivate the tool at anytime while drilling or tripping. Weatherford and Marathon Oil worked on this tool in collaboration.

Reconnect restores surface control to SCSSVs

Baker Hughes has commercialized its Reconnect technology, which restores surface control to subsurface safety valves. Developed by BJ Services, the system provides an alternative for re-establishing surface hydraulic control to surface-controlled subsurface safety valves (SCSSV) that are inoperable due to compromised control lines or if the installation of a storm choke is undesirable. This technology is also a viable option for wells that were not completed with SCSSVs.

The system includes a wireline-retrievable safety valve, a through-tubing replacement control line that strings into the new valve assembly and a wellhead adapter. Installation requires only a minimal crew and equipment suitable for almost any platform or well site.

High-temperature BOP uses advanced elastomer seals

Double E has introduced its new high-temperature blowout preventer, equipped with advanced elastomer seals. It’s designed with a vertical bore up to 6 ½ in. and is available with a choice of flanged and threaded connections. It can be ordered for standard or H₂S service, manual or hydraulic operation.

Smart Solutions for cranes

Konecranes has introduced Smart Solutions, a tool kit of intelligent crane features that can be bundled to tailor a new or existing crane to solve specific material-handling challenges. Features include sway control, positioning control, area control, load float and brake slip supervision. The kit protects the crane’s structure by reducing shock load, preventing skewing of the bridge, and preventing overloading.

A vital feature of Smart Solutions is anti-sway technology that prevents the load from swinging during crane travel. Sway control allows operators to safely move loads at higher speeds while positioning the load more accurately. Standardized automation is offered.

New ballast water treatment system meets new regulations

A new ballast water treatment solution, the Wärtsilä BWT 500i, has been launched to meet the latest and most stringent environmental regulations for ballast water management. Delivery of the first systems is expected to commence during Q2 2011. The system treats ballast water via a two-step process, first by filtering out larger organisms and particles, then by ultraviolet disinfection. The UV irradiation either kills the remaining organisms or renders them incapable of reproduction. Each unit is capable of treating 500 cu m of ballast water per hour, with the possibility to install several units in parallel for higher flow rates.

Database helps track NPT

Athens Group’s new Requirements and Issue Tracking Database tool helps reduce nonproductive time (NPT) by providing a central location for logging and tracking all control systems software-related requirements and issues. Using the database, the company was able to identify 865 issues during the engineering phase of a recent newbuild project. Nineteen of these issues were critical and involved problems with the anti-collision system, drilling emergency stop command, and BOP control system. Of the remainder, 157 issues posed considerable risk and 689 issues posed moderate risk. Had these problems been left undiscovered until the operations phase, Athens believes that resolution would have cost tens of millions of dollars.

Oil rig count on land to surge to 50% of total in 2011

James Wicklund

Held by production and joint venture spending in the shale basins have kept the US land rig count higher this year than you might expect, judging from natural gas prices, said James Wicklund, principal at Carlson Capital. But come 2011, industry will have to look to horizontal drilling in oily plays to keep the pace of activity up, he said.

Especially in the Haynesville, which appears to be having the biggest impact on gas over supply in 2010, activity should start to roll over by the end of Q1 2011. “Considering it’s costing $10-$11 million to drill a well and gas is selling for $4, it is cheaper for you to go ahead and lose the $4 million to drill the well than let the $6 million you paid for the property to expire. So drilling to hold acreage will keep up through the first half of next year, but you might see the first signs of weakness in the first quarter.”

But those rigs will just go elsewhere, he added, especially to the horizontal oily plays. Industry has come to realize that it can take its horizontal drilling and completion technology, honed over the past few years of drilling in tight gas shales, and apply it to tight oil reservoirs. “The realization has been hitting through this year that the returns on drilling for oil with today’s technology are much greater than the returns on drilling for gas,” Mr Wicklund said.

“Now you’re looking at suddenly the Permian Basin becoming one of the hottest basins in the US. A year ago if you told anybody on Wall Street that the Permian Basin was going to be the hottest basin going, they’d have rolled their eyes and laughed at you.”

According to Mr Wicklund, the oil rig count on US land has increased from 20% of the total in January 2009 to 40% now. He’s confident that number will go up to at least 50% next year. “That’s a big shift. A couple of years ago, everybody was claiming we’re not in the oilfield service business, we’re in the gas field service business. Nobody wanted to be associated with oil drilling. Boy, that’s changed in a hurry.”

The hot plays in 2011, he believes, will be the ones with oily reservoirs, such as the Permian Basin, the Eagle Ford, the Bakken and the liquids-rich portion of the Marcellus. With natural gas, he expects to see a slow decline in activity start anytime now. However, “it won’t pick up any meaningful traction until middle of 2011. Even then I’ll only see it fall a couple hundred rigs.”

He continued: “That will be overshadowed by crude oil drilling. I actually look for domestic onshore drilling activity to pick up by 5% to 8% next year, with the skew definitely going toward more oil than gas.”

PRODUCTION & DEMAND

The emergence of the shale plays has completely changed the paradigm for the US natural gas market, Mr Wicklund said. A common belief was that industry was running on a treadmill. If we slowed down at all, production would drop significantly. “The idea was that if the rig count dropped 5% to 10%, production would drop 10% to 20%. Instead, the rig count dropped 57%, and gas production went up – and has consistently gone up ever since the rig count bottomed.”

Going back to 2001 and 2002, the biggest complaint in the E&P industry was that there were no prospects in the US to drill. “Today we have a 15-year inventory of gas prospects already identified by the industry,” he said.

Because the price of natural gas remains soft – and Mr Wicklund doesn’t believe it will rise above $5.50 anytime soon – demand should start to pick up next year. “You usually do when something gets cheap,” he said.

The problem with that is, because natural gas had been portrayed for years as a scarce and expensive resource, Americans haven’t geared up to use it. It will take years to move the consumption needle, especially when it comes to using compressed natural gas (CNG) as a transportation fuel. Putting infrastructure in place will be key to moving that process forward. A plan unveiled in September 2010, backed by House Republicans, would spend $55 million to transition Pennsylvania’s 16,000 vehicles to run on natural gas instead of gasoline and provide tax breaks for private businesses to convert their vehicles. The legislation would also mandate the construction of natural gas fueling stations along the Pennsylvania Turnpike.

“I think those types of plans make sense,” Mr Wicklund said. “If we can come up with an incentive for private enterprise to develop the natural gas distribution network, that would be huge.” He believes that a company can expect a payback period of about 18 months for converting a fleet of 70 vehicles to CNG – even without government subsidies. “I think you are going to see a gradual shift to more use of natural gas for transportation purposes, but you do need more infrastructure.”

Outside the United States, there is potential for shale drilling in numerous areas – but that’s just a long-term potential for now. First, most countries don’t have the same level of natural gas infrastructure in place as the US. Second, there’s the issue of mineral rights. “If I’m going to drill in your back yard, you don’t mind because I’m going to send you a check. But if it’s Poland, Australia or China, I’m going to drill in your back yard and, by the way, you don’t get any of it. You’re not going to like that nearly as much,” he said.

He believes that shale drilling will be tested in many countries outside North America, but there won’t be meaningful production over the next five years.

OFFSHORE DRILLING

Although Mr Wicklund sees the US land drilling market continuing next year “at a decent pace,” he predicts the Gulf of Mexico offshore segment will have to struggle a bit more. “I don’t think we’ll see a deepwater well drilled until April (2011) at the earliest, and that’s probably optimistic.”

In the shallow water, he commented: “I think it will pick up, but it will still disappoint. It will be slower than people expect.”

Additionally, the number of companies that operate in the Gulf of Mexico will begin to decline. “That’s just a guarantee,” he said, pointing to Plains E&P as an example. The company announced in September that it was selling its GOM shallow-water properties to McMoRan Exploration for approximately $818 million. “I think they’re just going to be the first of several,” he said.

And it looks as if Plains E&P has decided to put more emphasis on onshore prospects instead. In October, the company announced plans to spud up to 19 horizontal wells in 2010 in the Texas Panhandle Granite Wash development and to boost that number to 25 in 2011. It also acquired approximately 60,000 net acres in the Eagle Ford in South Texas for $578 million in cash.

Outside North America, Mr Wicklund sees steadier markets in the North Sea, the Middle East and Asia/Australia. “Saudi Arabia surprised everyone recently by paying very competitive rates for jackups to develop their gas markets. Indonesia has been a bit of a surprise, too. You’re seeing a lot of the equipment and subsea companies expanding their presence in Southeast Asia because of the higher-than-expected activity in the South China Sea, Malaysia, Indonesia and Australia.”

For deepwater, West Africa seems to be going strong, he said, while Brazil could be the saving grace – if Petrobras decides to hire existing deepwater rigs for their offshore development programs rather than build additional rigs locally.

“It depends on whether Petrobras is more concerned with competitive economics or nation building,” Mr Wicklund said. “I’d go for nation building.”

Jump in gas prices is coming – just a matter of time

George Littell

George Littell, partner at Groppe, Long & Littell, has some good news for US land drillers: He believes there will be a big increase in natural gas prices, followed by a substantial increase in dayrates, next year. “It’s just hard to pin down the timing,” he said.

He points out that, over the past couple of years, there has been a significant decrease in drilling activity in every onshore area outside of the shales. That’s now coupled with an ongoing de facto moratorium in the shallow-water Gulf of Mexico, which no definite end in sight. Yes, shale gas production has grown very fast, he acknowledged, “but shales are still less than 20% of total production. Once the declines in all the other production overwhelm the shales … the bottom will drop out on production.”

He adds that over 40% of shale gas production is in the Barnett. “Production in the Barnett is flat… They cut rig activity in the Barnett in half. Just adds up that, at some point, you won’t get enough from the Haynesville and others. At some point, you probably will get a substantial rollover in US gas production.”

When that point is reached, “it will put tremendous pressure on gas prices. They might double. It’s just under $4 at the Henry Hub now, so it will go to $8 at some point,” Mr Littell said.

As that happens, land operators will be looking to increase their drilling activity by 30% to 50%, he projected.

“After this prolonged downturn, I seriously doubt the drilling contractors can respond to that very quickly. Even if you had the iron, where do you get the crews?” He believes there will be a period of increased dayrates, perhaps in the range of 20% to 30%, followed by a gradual increase in activity.

For 2011, Mr Littell is projecting a 10% to 15% higher rig count over 2010. “This depressed period is very similar to the late ’90s. After that, there was a big adjustment in gas prices in 2000. It took two to three years to really ramp up. This (downturn) has been so traumatic.”

As for what Mr Littell calls the “gold rush” in the shale basins, he believes a lot of shale drilling “will settle down” next year.

Although shale gas production has grown very fast, George Littell believes they aren’t enough to make up for the significant declines in drilling activities elsewhere to keep production up. “Shales are still less than 20% of total production. Once the declines in all the other production overwhelm the shales ... the bottom will drop out on production.” When US gas production rolls over, he said, that’s when industry can expect gas prices to surge upwards.

Operators have been stuck with an inventory of leases to drill before they expire, so they have been going through a process of sorting out what gets drilled and what is marginal. “Is anybody making any money when Henry Hub’s at $4?” he asked. “It’s just wildly uneconomic.”

As for the growing trend of drilling oily reservoirs using horizontal drilling and completion techniques, Mr Littell believes that will continue to be hot in 2011. Yet he also believes “that’s already happened to the extent it can be done.”

“I think everybody would love to have high liquids content shales. They’re just hard to find,” he said.

Limitations with frac services could also prove to be a bottleneck as activity tries to pick up next year. “They just keep building up more and more of a backlog of wells that need to be fractured, just because there aren’t the crews and the equipment to do the fracturing,” Mr Littell said.

Are the stimulation and other well servicing companies not expanding their businesses enough? “I think a lot of them are scratching their heads about just how much of this they want to do. In the sense that you get geared up for the gold rush, then it goes away. You put all this money into the trucks, equipment and people, and all of a sudden you don’t have as many frac jobs to do. I think they’re very leery of it,” he said.

PRICE OF OIL

Mr Littell projects oil prices will average in the low $70s in 2011. “The tricky thing is to figure out what the range will be. I haven’t tied that down yet, but it’s $60 to $85. That’s an interesting oil market.”

What OPEC does could be an important influence too. “They really are restraining somewhere between 4 and 5 million (barrels) a day of producing capacity… That’s an unstable situation. There will be a big temptation when everything’s looking better to go up on the production – a lot rather than a little. That’s something that can be corrected, but, in the meantime, it gives you a nasty short-term drop in prices,” he said.

Surging demand may push frac industry up 20% in 2011

John Spears

Hydraulic fracturing activity has grown tremendously through 2010 – and so have prices. According to John Spears, president of Spears & Associates, costs for frac jobs have risen by 25% to 30% over the course of this year. “A lot of service companies that provide frac services have begun to very aggressively add to their fleet of equipment. We think the frac fleet size will increase about 25% this year and another 20% next year,” he said.

At the same time, due to the remarkable increase in demand, lead times for frac jobs have also risen steadily. “Right now we’re probably looking at six weeks or a little bit longer in a lot of places where you’re talking about big, multistage frac jobs or a new well… In fact, you may be scheduling the frac job before you begin to drill the well.”

His company estimates that overall land drilling activity in the US will increase by 12% to 14%: The oil and oil-related rig count will grow by about 50% from 2010 to 2011 while the gas-directed rig count will fall about 10% over the same period. “Overall we think it will go up about 12% to 14%,” he said, adding that the average total rig count for 2011 is projected to be approximately 1,725. “We think it will probably top out somewhere in the 1,800 range, maybe 1,900.”

The growth part of the market will continue to be the horizontal drilling plays, including both gas shales and oil shales. “Rigs geared for that type of work will continue to see very high utilization, probably in the 90% range. Whereas the more conventional rigs will probably see their utilization remain in the 40% to 50% range next year.”

He thinks the shift that started this year toward oily reservoirs or reservoirs with liquids-rich gas will sustain through 2011. “The Bakken play in the Williston Basin of North Dakota has sort of been the poster child for these new oilfields … as operators make use of horizontal drilling techniques and frac jobs to get after these oil zones that had been ignored in the past… I think we’ll continue to see a number of announcements over the next year or so as operators come back and say, we’re now going into these older oil zones and looking at what they may have passed over.”

At the same time, Mr Spears urges the industry to pay attention to a couple of potential hurdles to land drilling. One is the still-ongoing fight over hydraulic fracturing. “Taken to its extreme, it could be a real threat to the industry,” he said, adding that he’s hopeful reasonable regulations will be adopted. But industry also must do more to educate regulators and the public so they understand the fracturing process, he said.

Another issue is access to water, which is a significant requirement for hydraulic fracturing. “The industry has to work out what to do with both the volumes of water being used and what you do with the frac water once it’s recovered. Access to water for fracking is becoming a big issue.”

OFFSHORE OUTLOOK

In the Gulf of Mexico, the outlook isn’t nearly as healthy as that for land drillers. “The offshore market will be a head scratcher for all of us for a long time,” Mr Spears said. “We think the deepwater part of the Gulf of Mexico will be very slow to come back. I think it will be about two years before we see deepwater activity even half the level that it was before the Macondo blowout.”

In the shallow water, too, he thinks it may take six to 12 more months to return to the pre-Macondo level of permitting and drilling activity.

Outside of the GOM, “we see a much steadier picture. We see activity up in most markets outside the US,” he said. Brazil, West Africa and parts of Southeast Asia will be good markets for deepwater rigs. “The big question will be what kind of rates they can get for their rigs. We may see rig rates weaker next year than anticipated,” he added.

In the Middle East, most operators have held steady through 2010, after going through a period of retrenchment in 2009. “I think we’ll see levels next year at or maybe slightly above what we’ve seen in 2010,” he said.

Gas exploration in the Middle East should also be monitored. “There’s a lot of gas-related work going on. They’re trying to use it for their own consumption to support the exports of the petrochemicals industry and to free up some oil for exporting. It’s a slightly different mix of work than what we’ve seen in the past.”

Mr Spears adds that, because natural gas is priced relative to oil in most places outside North America, gas prices can often be twice the level seen in the US. When it comes to LNG, this has helped to keep LNG imports from coming into the country. “If you’re an LNG producer, you’d rather sell your cargo someplace other than the US because you’ll generally get a higher price for it.”

In the US, he projects natural gas prices to stay within the $4-$5 range for 2011 while oil prices will likely continue to trade within $70 to $80. “We don’t see a lot of movement in oil or gas prices next year,” he said.

Mainland CEO: Early birds get the worms in shale gas plays

As of mid-October, natural gas prices were still hovering well below the $4 mark. Yet many of the shale basins – the Haynesville, the Marcellus, the Eagle Ford – are bustling with more activity than ever. How are operators making the economics work?

For Mainland Resources, established in 2008, the answer is simple: Get in early.

“Everybody can do their best to drill cost-effectively, but what you can’t change is what you paid for the leases. If your cost basis before you even start to drill a well is high, then really there is nothing you can do other than to wait for product prices to increase,” said Mainland CEO and director Nicholas Atencio. Early entrants, like Mainland with the Haynesville, pay industry-standard prices. Those later to the game will end up paying quite a bit more, he said.

The company, along with partner Petrohawk, became a major player in the Haynesville in the East Holly field of Louisiana over the past couple of years before selling that acreage. “We sold that level,” he clarified. “We kept everything above the Haynesville,” where the company is trying to quantify reserves now in order to plan additional wells to drill in 2011.

Mainland drilled three wells on its East Holly acreage this year and is drilling another now in Jefferson County, Miss. The latter will consist of a deep test of a Haynesville prospect; the proposed depth for the well is 22,000 ft.

Although the company is now drilling just for Haynesville gas, Mr Atencio said they are looking into other types of shale activities in the Mississippi that have the potential to produce oil.

Figure 1: A study of dropped objects at Shell determined that drilling equipment, lifting equipment and tubulars should be key focus areas for a prevention campaign.

Safety is always our top priority. We aim to have zero fatalities and no incidents that harm people or put our neighbours or facilities at risk. When we analyzed the biggest risk areas in our wells operations, we found dropped objects to be the largest category of high-potential incidents (HIPOs) in Shell’s wells operations. We took it as a clear call for action and started a campaign to make a change.

The clear downward trend of HIPOs in the first half of 2010 suggests that it’s working.

HIGH-POTENTIAL INCIDENTS

We define a HIPO as an unplanned HSE incident or near-miss that has the potential severity to cause permanent disability or death. For dropped objects, this is regardless of any barrier that may be in place to prevent personnel from walking into a danger zone.

HIPOs involving dropped objects have accounted for the great majority of potential and actual fatalities in Shell’s well operations over the past few years, including three fatal accidents since June 2008.

Figure 1 shows the different categories of dropped objects against the number of times a HIPO has occurred. This indicates that drilling equipment, lifting equipment and tubulars are key focus areas.

Figure 2: Shell is trying to eliminate the use of these “forbidden” equipment as they are often the cause of dropped objects.

LAUNCHING CAMPAIGN

Determined to eliminate dropped objects, we launched the Prevention of Dropped Objects campaign in mid-2009. It involves everyone who works on drilling, completions and well interventions, including Shell staff and contractors.

The campaign is just one of several ways in which we seek to align with our drilling contractors and international service contractors on safety improvements. Others include the development of Joint Safety Improvement Plans, compliance with our Life-Saving Rules and Temporary Pipework Standard, distilling and sharing key actions arising from HIPOs, and carrying out joint worksite safety audits at a minimum of two locations per contractor per year, with senior management participation.

The rollout of the Prevention of Dropped Objects Manual was the first step in the Prevention of Dropped Objects campaign. It is aimed at management and supervisory staff for Shell and its contractors and is based on four principles, each of which has a series of mandatory requirements for Shell staff and its drilling, completion and well intervention contractors. These principles are:

• Contractors providing equipment and personnel on Shell well sites shall have a dropped object prevention scheme.

• A systematic dropped object inspection programme shall be in place.

• Worksite hazard management for dropped objects shall be in place.

• Audits to check for compliance with the dropped object prevention scheme shall be in place.

We are also determined to stamp out the use of forbidden equipment (Figure 2), which are often the cause of dropped objects, and reinforce and mandate the use of proper equipment, including the use of tethered tools.

Managers, supervisors, operations staff and contractors have adopted the manual and use it across different countries and cultures at more than 100 rig locations and up to 200 well completions and intervention activities every day.

It is also supported by a pocket-sized ABC Guide to Dropped Object Prevention, which is proving popular and useful.

Figure 3: The prevention campaign uses training animations to demonstrate good and bad practices in a language-free setting so they can be used at well sites worldwide.

IMPLEMENTING CAMPAIGN

It is clear that issuing the manual was only the first step in a much wider campaign. The manual itself is not enough to change behaviour and working practices. We are determined to make a full-scale change via the Prevention of Dropped Objects campaign, which will involve everyone from management to the worksite employees and contractors who are at risk of injury or worse.

The implementation is challenging, but it is essential that it is rolled out and embedded in all our locations. To succeed in eliminating dropped objects, it is imperative that all Shell wells staff and contractors understand and comply with the mandatory requirements set out in the Prevention of Dropped Objects Manual.

Regional DROPS Focal Points (DFPs) are responsible for ensuring that the requirements for preventing dropped objects are communicated to the local teams, including contractors, and then tracking the status of compliance with mandatory requirements for management review.

The DFPs also appoint and brief local DROPS leads who run the DROPS campaign at their site. A key role for a DROPS lead is to conduct a gap analysis to identify what has to be done to comply with the manual. An action plan for improvement at the respective location is essential to success.

COMMUNICATION, TRAINING MATERIALS

There are six campaign topics supported with communication and training materials that are being rolled out on a quarterly basis until summer 2011. The topics are: tools at height; tubular handling; No-Go Zones and Red Zones; handling lubricators and tool strings; drilling equipment; and winches and tuggers.

Figure 4: Shell recorded 18 dropped-object HIPOs at the start of 2010. By August, the number had been reduced to only one incident.

Training for each topic includes cascaded learning sessions to be run at the work site, as well as awareness animations and practical exercises to convey key knowledge and skills. The animations, delivered on DVD, are an innovative way of getting across key learning points (Figure 3). The cartoon characters demonstrate bad and good practice in a humourous way. They are also language-free so can be used worldwide.

Communications includes presentations for managers and supervisors, as well as a regional Drops Focal Points Forum to clarify expectations and share learnings; monthly teleconferences; articles for internal and external publications; a Drops website; and posters for each topic.

We have implemented the training and communication packs for Tools at Height and Tubular Handling. As this article is published, the material for No-Go Zones and Red Zones will have been launched.

We hope that our investment in this training is another way of showing how determined we are to eliminate dropped object incidents throughout the business. We are encouraging all of our own and contractor staff to support and participate in the campaign and demonstrate, by their actions, that compliance with the requirements of the Prevention of Dropped Objects Manual and eliminating dropped objects is important to them.

WHAT’S NEXT?

It’s not enough to roll out materials and training; therefore, we monitor and measure that change is happening. Audits are taking place to check for compliance against the requirements of the Prevention of Dropped Objects Manual through joint site inspection visits, annual contractor facility audits and local area compliance audits. The success of the campaign is demonstrated by the downward trend of HIPO drops incidents throughout 2010.

At the start of the year we had a high of 18 drops HIPOs in a month, and this has reduced to only one incident in August 2010. It is important to stress that we still have a long way to go. Do not think the job is complete; it will require constant vigilance to Stop Dropped Objects.

Gordon Graham is vice president wells HSE, projects and technology, Shell International Exploration & Production.

This article is based on a presentation at the 2010 IADC Drilling HSE Europe Conference & Exhibition, 29-30 September, Amsterdam.