bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: Deepwater Projects (May 2011)
Authors: Olson Karen
Published: February 2015

Technology Focus

Lessons (Hopefully) Learned

The BP Macondo incident, late April 2010, profoundly changed the way work will be performed, on and offshore. After losing 11 men, injuring others, and losing an exploration rig, it is an appropriate time for the industry to evaluate what changes to industry standards are necessary to ensure that a similar event does not occur again.

The incident affected people’s lives in many ways, both seen and unseen. Obvious issues include lost tourism in several states, dead marsh and fish, idled rigs and workers, and areas placed off-limits to exploration. Nearly a year after the incident, the rig count in the Gulf of Mexico is down 50%. The unseen and to-be-determined issues include the uncertain regulatory field still arising from the event, previously marginal fields now shelved, and abandonment of or significant delay in developing high-pressure large-oil-in-place fields. Undoubtedly, these results will have a major effect on national energy security and will lead to higher energy costs.

What, then, are the lessons learned? First, management must not lose focus on the risks, however remote the odds. Second, when assessing staff adequacy, critical and honest evaluations of people and skill levels including technical expertise and requisite experience are required. In this context, technical or operational expertise should not be ignored, even if there is additional cost or time. Remaining lessons pertain to proper planning and vendor management. Proper equipment planning (availability and functionality) is required. Vendor management (must ensure that each project requiring new/sophisticated equipment has sufficient service-company-management buy-in and adequate resources and support) will be critical when offshore work returns. Striking the appropriate balance between cost and safety should err on the side of safety.

Now for the good news: two entities were established to respond to spills, and lessons learned by BP from Macondo can be used to avoid similar incidents.

Companies must be careful to avoid thinking that such an event “can’t happen to us.” Careful evaluation of risks, coupled with a realistic and thorough evaluation of company practices and processes, could help avoid another Macondo. Low-probability events can/do happen, sometimes with draconian consequences. Offshore development can be highly profitable, but the risk/return tradeoff should not be ignored.

Deepwater Projects additional reading available at OnePetro: www.onepetro.org

SPE 140498 • “Challenges of Designing Multistage Frac Packs in the Lower Tertiary Formation of the Cascade and Chinook Fields” by Ziad Haddad, SPE, FOI Technologies, et al.

SPE 137220 • “GOM Deepwater Field-Development Challenges at Green Canyon 468 Pony” by Michael H. Weatherl, Hess Corporation. (See JPT, April 2011, page 70.)

SPE 140228 • “Case History:  Lessons Learned From Retrieval of Coiled Tubing Stuck by Massive Hydrate Plug When Well Testing in an Ultradeepwater Gas Well in Mexico” by Victor Vallejo Arrieta, Pemex, et al.
New Approach To Extend Horizontal-Drilling Reach
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 137821, ’New Approach To Improve the Horizontal-Drilling Reach,’ by O.M. Vestavik, SPE, H. Syse, O. Hole, SPE, and J. Aleksandersen, Reelwell, prepared for the 2010 CSUG/ SPE Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. The paper has not been peer reviewed.

A drilling method was developed to enhance extended-reach managed-pressure drilling. A conventional drillstring with a special inner string forms a dual concentric drillstring (DCD). The inner string is used to remove drill cuttings from the bottom of the well. A separate hydraulic-fluid system is used to push the drilling assembly forward using fluid pressure from the surface. Development began in 2004, and the system has been through several full-scale operations in Norway. In 2009, the DCD method was used to directionally drill the 81/2-in. section of an onshore well. 

Introduction

As targets for new petroleum resources become increasingly challenging, there is a need for new technology to keep exploration and production costs at an acceptable level. Development of the DCD method was supported by the Research Council of Norway, Statoil, and Shell.

DCD method

The DCD method, shown in Fig. 1, is based on conventional drilling, with the following components added to the system.

The dual drillstring (DDS) facilitates closed-loop circulation of the drilling fluid. The cuttings are trans-ported to the surface by the drilling fluid through the center pipe, leaving the wellbore annulus free of cuttings.

The top-drive adapter (TDA) is a dual-conduit swivel that facilitates rotation of the drillstring and accommodates the discharge and return conduits and a slip ring for power and data transmission.

The dual-float valve (DFV) enables downhole pressure isolation of the well and facilitates controlled-pressure drilling and nonpressured pipe connections.

The sliding piston is used to pump the bottomhole assembly (BHA) into the horizontal section of the well. The piston provides hydraulic weight on bit (WOB) and provides the ability to push the limits of extended-reach-drilling.

The flow-control unit is a control valve for the active drilling fluid to ensure constant downhole pressure during drilling and pipe connections. The unit is equipped with pressure and flow sensors on both the drilling-fluid inlet and the return lines. A computer monitors and controls the status of the well. An annulus-control unit is used to keep a constant pressure in the annulus behind the piston.

A main difference between this method and conventional drilling is the circulation path of the drilling fluid. In conventional drilling, the fluid returns through the wellbore annulus. The DCD method pumps the drilling fluid into the DDS annulus through the TDA. The drilling fluid flows down the DDS annulus to the DFV, which terminates the DDS at the top of a conventional BHA.
Opportunity, Challenge Meet on Arctic Horizon
Authors: Parshall Joel
Published: February 2015

On the stark expanse of the Milne Point field on the Alaska North Slope, the BP Mount Elbert well tests the reservoir productivity of methane hydrate in a joint project with the National Energy Technology Laboratory of the US Department of Energy during 2007.

The Arctic represents a large expanse of opportunity for discovery and development of oil and gas resources, but one matched equally with technical challenges that test the limits of the industry.

In the 2008 Circum-Arctic Resource Appraisal (CARA), covering 33 geologic provinces considered prospective for petroleum, the United States Geological Survey (USGS) calculated that the sum of the mean estimates for each province indicated that 90 billion bbl of oil, 1,669 Tcf of gas, and 44 billion bbl of natural gas liquids (NGL) remain to be found in the Arctic, of which 84% was expected to lie in offshore areas. The study included only resources that are technically recoverable, that is, those considered recoverable using existing technology.

The obstacles of ice, the most severe weather conditions, seasonal constraints, minimal infrastructure, daunting and uncertain logistics, and the high cost of operations begin but do not end the list of challenges to Arctic exploration and production.

“The extensive Arctic continental shelves may constitute the geographically largest unexplored prospective area for petroleum remaining on Earth,” the study said.

The challenges may explain exactly why that is so and cause some to conclude that these areas will always be underexplored, with many of these estimated resources never developed. Yet the matter can be viewed quite the opposite way. As the area is so underexplored, will we someday find these estimates low if we answer the challenge to explore and develop the Arctic?

Unconventional resources, such as coalbed methane, methane hydrate, oil shale, and tar sand, were explicitly excluded from the 2008 study. Perhaps that is just a footnote. But considering what has happened in only the past few years with the tremendous growth of shale resource estimates, perhaps it is not. It is questions like that, and always knowing that there is so much we do not know, that keep the Arctic on the horizon of opportunity for the oil and gas industry.
Assessing the Magnitude and Consequences of Reservoir Souring
Authors: Schofield Mick , Stott Jim
Published: February 2015

Reservoir souring

Reservoir souring, defined as the unplanned increase in hydrogen sulfide (H2S) in produced fluids during field life, is a growing concern for the petroleum production industry. H2S is a poisonous, dense gas with serious safety implications; it can lead to sudden catastrophic failure of nonresistant metallic materials from sulfide stress corrosion cracking or hydrogen-induced cracking, and it can enhance pitting corrosion rates.

But how does reservoir souring develop, and how can its consequences for materials be anticipated? Consideration also needs to be given to the currently available options for souring control and their shortcomings.

Despite the significant advances that have been made over the past 30 years or so in the understanding of H2S- related materials degradation mechanisms, H2S still causes many failures every year. While it may be understandable that such failures continue to occur in operating environments where reservoir souring is a new phenomenon, failures are also occurring where the industry is mature.

For example, recently in the UK, a carbon steel pipeline transporting sour hydrocarbons onshore failed by sulfide stress cracking (SSC) after 6 weeks of operation, necessitating replacement at a cost of GBP 100 million.

Over 2000–01, sour gas pipelines failures, including those affected by both microbial and chemically induced corrosion, accounted for 35 (4%) of the 952 pipeline failures in Alberta, Canada.

The challenge of dealing with H2S is likely to rise in importance as an increasing number of high-temperature, high-pressure (HTHP) reservoirs are exploited in the future. This will require more widespread use of corrosion resistant alloys (CRAs), increasing the costs of wells and downstream equipment.

Therefore, we need more corrosion data on a range of alloys when there are fewer materials engineers (particularly metallurgists) coming into the industry and fewer corrosion testing facilities in steel companies, meaning that operating companies and even fabrication contractors are having to take on the task of generating materials susceptibility data.

H2S Generation and Mobility

Reservoir souring is the production of increased concentrations of H2S in well-stream fluids from production wells subject to water injection for secondary recovery. It is generally acknowledged to be caused by the activity of a specialized group of microorganisms, the sulfate-reducing bacteria (SRB). Low populations of SRB cells are ubiquitous in seawater and many other natural waters that are used for secondary recovery.

Biogenic H2S originates solely from SRB activity in the water phase and subsequently partitions between water, liquid hydrocarbon, and gas, dependent on temperature, pressure, the pH of the aqueous phase, fluid phase ratios, and a number of other factors. However, the progress of reservoir souring is routinely measured and expressed in terms of H2S concentrations in the gas phase at separator conditions and the corresponding partial pressures of gaseous H2S.
Technology Focus: Deepwater Projects (May 2012)
Authors: Salies Jacques B.
Published: February 2015

Technology Focus

No word defines deepwater projects better than “innovation,” and on 25 February 2012, one of the most innovative field-development projects came on stream: Cascade and Chinook (C&C) in the US Gulf of Mexico (GOM). One well is producing from Cascade to the first floating production, storage, and offloading (FPSO) vessel in the US GOM. The project brings several firsts and innovations that will be available to the entire oil industry in the near future. I would like to call attention to some of those innovations. First, the FPSO uses a detachable buoy that allows early installation of the buoy and all umbilicals before arrival of the FPSO. This feature will allow the FPSO to disconnect and sail away from hurricanes, avoiding damages to the facilities. C&C also presents the first freestanding riser in the US GOM. Subsea boosting will increase production and reduce workover costs. These examples are just a few that show innovation applied to a deepwater development.  I believe strongly that C&C will lead the way for future development of Lower Tertiary plays in the GOM.

I selected one paper for this feature that describes the planning, logistics, and technology of the two largest deepwater high-pressure perforation jobs executed successfully in the GOM; certainly, this provides very interesting reading if your company is in the Tertiary play or is planning to be.

Drilling management in deep water has always been a great challenge because of several constraints, including high cost; well engineering (exploratory wells); logistics (remote locations); health, safety, and environmental (local and international laws); licenses; and personnel management. One of the papers presents a very objective and clear explanation of the well-management process, describing the design methodology and the well-execution procedures used by Petrobras International in a remote and challenging area. This methodology can be applied to any well and could bring huge benefits for any drilling operation.

Are you lost in a “cloud” of drilling data? You are not the only one! Drilling-data management is one of the biggest challenges in our industry today. One of the feature papers presents solutions, gives examples, and shows the benefits of a correct use of drilling data.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 145259 Drilling and Underreaming in the GOM Deepwater Ultradeep Lower Tertiary: History of a Record Run in the World’s Deepest Oil or Gas Well by Charles Ubaru, Baker Hughes, et al.

SPE 151487 Continuing Efficiency and Assurance Advances for Deepwater BOP Testing by C. Mark Franklin, SPE, IPT Global, et al.

OTC 21821 Versatility in Answering the Challenge of Deepwater Field Developments by Jackson D. Bullock II, Subsea 7, et al.

SPE 140954 Worldwide Pore-Pressure Prediction: Case Studies and Methods by Haixiong Tang, CNOOC, et al.

OTC 22092 Deepwater Drilling for Arctic Oil- and Gas-Resources Development: A Conceptual Study in the Beaufort Sea by N. Pilisi, Blade Energy Partners, et al.
Efficient Perforation of High-Pressure Deepwater Wells
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 21758, ’Efficient Perforation of High-Pressure Deepwater Wells,’ by William Sanders, SPE, Carlos Baumann, SPE, and Harvey Williams, SPE, Schlumberger, and Flavio Dias de Moraes, SPE, Jonathan Shipley, Martin Bethke, SPE, and Scott Ogier, SPE, Petrobras, prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed.

Thousands of perforating jobs are conducted successfully worldwide each month. However, for a small number of jobs, typically high-pressure deepwater wells, gun shock is a real and significant risk. The Cascade and Chinook projects presented the two largest deepwater high-pressure perforation jobs to date in the Gulf of Mexico (Fig. 1). These Lower Tertiary well completions have gross perforation intervals greater than 800 ft and downhole pressures higher than 19,000 psi. Perforating all intervals with long gun strings and then frac packing multiple zones in a single trip saves substantial rig time compared with performing conventional stacked frac-packed completions requiring multiple trips per perforated zone.

Introduction

Perforating several intervals in one run was required to complement a single-trip multizone frac-pack system in which all downhole packers, screens, and service tools are run at once and all zones are stimulated in a single trip. Planning, mobilizing, executing, and reviewing multizone perforating jobs at wellbore pressures higher than 19,000 psi and in water depths greater than 8,000 ft presents many challenges. Operational risks inherent to perforating multiple zones in a high-pressure deepwater environment were minimized by using a simple and reliable approach built on previous experience from high-pressure deepwater perforation jobs. Cost reduction is the main driver because of the very high daily cost of deepwater operations. With a one-way-trip time of 18–24 hours, eliminating just one trip in the well would save up to USD 2 million. Perforating three or four zones at once multiplies the savings.

Planning

Planning for these jobs began with evaluating the casing design configuration to ensure that the perforating bottomhole assembly (BHA) could be run in and retrieved from the well with no damage and that the casing could withstand the pressure requirements of the perforating operations.
Real-Time Optimization of a Highly Complex, Integrated Gas System
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150109, ’Successful Real-Time Optimization of a Highly Complex, Integrated Gas System: Intelligent Energy in the Real World,’ by Derek Gobel, SPE, Shell; Jan Briers and Frank De Boer, IPCOS; and Ron Cramer, SPE, Kok-Lam Lai, SPE, and Martijn Hooimeijer, SPE, Shell, prepared for the 2012 SPE Intelligent Energy International, Utrecht, the Netherlands, 27-29 March. The paper has not been peer reviewed.

Real-time optimization (RTO) was used by Shell Malaysia E&P on the integrated gas-production system in Sarawak. Models for real-time monitoring and optimization of wells and facilities were implemented on a gas-production network spanning more than 100 wells on more than 40 platforms across several production-sharing contracts (PSCs). Digital technology enabled field-based data to be used to support decision making and led to actions that ensure that production is optimized continuously.

Introduction

Traditionally, aspects of gas-supply security relate to reservoir management, development planning, and sustaining plant availability and integrity. With increased computing capabilities, increased attention is given to noncapital-expense-intensive ways to provide additional smaller-scale improvements to the performance of an asset. Production-system optimization (PSO) falls into this category.

The Sarawak asset has experimented with ways to improve continuous optimization of its production through model optimization. Implementation of a mixed-integer nonlinear programming model rendered valuable results for medium- and long-term planning. However, network complexity and the volume of required optimization calculations obviated application in the real-time domain. Subsequent unsuccessful approaches included use of rigorous process-engineering simulation and optimization tools linked to the data historian. Two commercial soft-ware packages were trialed, but neither produced results fast enough or was sustainable by local staff.

Context

The Sarawak integrated gas asset is in the South China Sea off the coast of Sarawak, Malaysia. It comprises three onshore liquefied-natural-gas (LNG) plants at the onshore LNG complex in Bintulu, four onshore customers and an LNG cargo-export facility, 50+ offshore hubs and jackets, 100+ wells, and numerous connecting pipelines. Sarawak is covered by five PSCs and has several active operators.

The asset produces offshore natural gas of variable composition that is blended in the source-system pipelines and liquefied in the onshore LNG plants in Bintulu. Associated condensates are collected and processed in the Bintulu complex. Constraints in the system are physical, planning, and contractual/commercial in nature.

Possible Optimization Approaches

Financial—Impractical. This approach constitutes the monetary bottom line: total profit after royalty, tax, and interest. The revenue is generated from gas and condensate sales at the going rates minus taxes and the costs of investments and operations.
Technology Focus: Multilateral/Extended Reach (May 2012)
Authors: Negrao Alvaro Felippe
Published: February 2015

Technology Focus

Mitigating Risks in Development Projects

Our industry has been involved in incidents that demonstrated the need of a new approach for evaluating and mitigating the risks in well construction.

The “what’s worked well in the past” conservative approach is not possible anymore, in face of the damaged trust of the public about upstream activity. Though the criticism soars against exploration and production activities, the industry has allocated substantial investments in research for new technologies aimed to preclude risk events of recent years. New procedures and technologies, in addition to existing ones, will be deployed in the near future to eliminate blowouts or underground contamination from upstream operations.

The initial results can be seen in field operations such as the application of managed-pressure drilling (MPD) for offshore and onshore, the use of long horizontals or extended reach in the shale plays, and new fluids and techniques for fracture treatments that minimize the amount of water required in such operations.

The effects of drilling operations in the shale plays of the USA are clear, but recent research will result in a consistent reduction of environmental damage. Research is minimizing fluid losses into reservoirs and helping with mitigation of well-control situations when applying the MPD technique.

The use of nanotechnology will provide fluids that improve fracture treatments through the control of fluid losses, with a subsequent reduction in the amount of fresh water required. Today, an average fracture treatment in the Barnett shale requires 235,000 bbl of water. These treatments are essential to reduce the number of wells and to improve the performance of the fracture treatments for environmental-impact reduction.

The use of extended-reach drilling or long horizontal wells, combined with multilaterals, will reduce the number of wells without impairing expected production. This will mitigate the effect on aquifers or shallow formations with a reduction in surface infrastructure. Some of the papers featured or listed for reading show advances in the technology of extended-reach and multilateral wells that will help achieve such objectives.

Finally, the combined use of extended-reach and multilateral wells, nanotechnology fluids, and MPD will result in a more environmentally-friendly operation with a cost-effective development plan, which is essential for improving the industry’s image.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 145400 Achieving Brazilian Extended-Reach-Drilling Records on the Polvo Project With Ultrahigh-Torque Connection by Nathan Biddle, Devon Energy do Brasil, et al.

IPTC 14258 Burgan Multilateral Campaign: A Success Story in Development of a Complex Siliciclastic Reservoir in Kuwait by Javed Ahsan, Kuwait Oil Company, et al.

IPTC 14823 Review of Ultrashort-Radius Radial System by S.K. Putra, Pertamina Upstream Technology Centre, et al.
More-Effective Plug-and-Abandonment Cementing Technique
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148640, ’Novel Approach to More-Effective Plug-and-Abandonment Cementing Techniques,’ by Thomas E. Ferg, Hans-Jacob Lund, and Dan Mueller, ConocoPhillips; Morten Myhre, Arne Larsen, and Patrick Andersen, SPE, HydraWell Intervention; Gunnar Lende, SPE, Halliburton; Charlie Hudson, SPE, M-I Swaco; and Cato Prestegaard, SPE, and David Field, Halliburton, prepared for the 2011 SPE Arctic and Extreme Environments Conference & Exhibition, Moscow, 18-20 October. The paper has not been peer reviewed.

The effectiveness of a permanent abandonment plug is measured by its ability to bridge the wellbore cross section, both vertically and horizontally, including all annuli, with a plugging medium that can withstand the harsh environment to which it is exposed (Fig. 1). A new method is presented that creates a permanent abandonment plug by use of a system that perforates uncemented casing, washes the annular space, and then mechanically places the cement across the wellbore cross section in a single run.

Introduction

Traditional methods of creating an annulus barrier in uncemented casing require removal of a section of casing by milling, cleaning the created open hole to remove swarf (i.e., metal filings or shavings produced by a cutting tool) and other debris, underreaming the section to expose new formation, and then setting a balanced cement plug. These operations can be time consuming and difficult to execute safely and effectively.

Fluids for use in section milling must have sufficient weight to keep the open hole stable and sufficient viscosity to suspend and transport swarf and debris to surface. The required fluid-viscosity profile for milling operations can generate equivalent circulating densities that exceed the fracture gradient of the exposed open hole, leading to losses while circulating, swabbing and well-control problems, poor hole cleaning, and packing off of the bottomhole assembly (BHA). The problems occur because not all swarf and skimmed casing remnants can be cleared from the wellbore. Swarf and casing debris can become strung out along the wellbore, lodging in the annular and ram blowout-preventer equipment, seriously effecting function. At the surface, handling equipment must be positioned and installed within the return flowline beyond the bell nipple and in front of the shakers to separate and capture the generated metal returns from the active mud system. An example of metal brought to surface during milling operations is shown in Fig. 2.
Achieving Deepwater Success
Authors: Pai Satish
Published: February 2015

Guest editorial

Despite some uncertainty in the global economy, the long-term outlook for energy demand remains strong and the industry will continue to be challenged to meet hydrocarbon supply over the next decade. In its latest outlook, the International Energy Agency estimates that approximately 32% of oil production needed by the end of this decade has yet to be discovered or developed, and by 2035 it will be closer to 50%.

In response to this challenge, the exploration and production (E&P) industry has become more ambitious in searching out new frontiers, with some notable successes over the past few years, particularly in deep water. More than half of all oil and gas reserves discovered worldwide over the past 10 years have been offshore and the majority of large finds have been in water depths of more than 500 m (1,640 ft). We are reminded that 10 years ago pre-salt reserves offshore Brazil were still not proven, and that deepwater discoveries in areas such as French Guiana, Tanzania, and Ghana were not even on our industry’s radar screens.

It is estimated that approximately 200 new deepwater fields will enter production over the next 4 years. By 2020, production from deepwater fields will represent about one-third of total offshore production, representing about 10% of total global oil supply. Deepwater well capex is expected to grow from USD 47 billion to approximately USD 128 billion by 2020, with 71% of this growth taking place in the Atlantic basin—particularly in Brazil, Angola, Nigeria, the US Gulf of Mexico (GOM), and Nor-way. Other countries with solid deepwater activity include Australia, Egypt, and India. To achieve this significant growth, an increase in the number of floater rigs is forecast, from 200 in 2008 to more than 400 by 2020—an average of more than 20 new rigs per year. This estimate is consistent with mid-term forecasts of new deepwater rigs and suggests that the trend will be maintained until the end of the decade.

Over the period 2013-2020, deepwater well costs are expected to slightly increase in real terms. While efficiency gains are expected in regions such as the US GOM, thanks to next-generation rigs entering the market and the continued integration trend of new drilling technologies, these will be offset by increasingly complex and deeper wells. Exploration and appraisal activity is set to continue along the same trends for the rest of this decade, with further expansion in basins with recent discoveries such as the Mexican GOM, Equatorial Atlantic, east Africa, and the eastern Mediterranean. Activity will also be strong in basins with less-recent discoveries but where technology and/or access drivers have opened additional opportunities, such as Brazil, west Africa, and the US GOM.
California's Monterey Formation Zeroing in on a New Shale Oil Play?
Authors: Beckwith Robin
Published: February 2015

Monterey Shale, California's Primary Petroleum Source Rock, Unlocking Its Complexities

The golden state’s Monterey Formation has been garnering a great deal of attention as a possible emerging liquids-rich shale resource that not only rivals plays such as the Bakken and Eagle Ford but towers above them in potential. Where did this news originate, what does it mean, and how does the Monterey’s future seem to be unfolding?

An Intriguing Report

In July 2011, the US Department of Energy’s (DOE) Energy Information Administration (EIA) issued a report titled “Review of Emerging Resources: US Shale Gas and Shale Oil Plays.” The introduction to the report clarifies that it is presenting a review of such resources only within the US lower-48 onshore area. The information presented in the review is based on a report, with the same title, which was prepared by INTEK, Inc. for the DOE, and is dated December 2010. 

The report identifies 19 significant shale gas plays in the US onshore lower-48 area—plays labeled, in a table, as “unproved discovered technically recoverable resources.”

It also named four significant shale oil plays in the US onshore lower-48 area—plays labeled, in a second table, as “technically recoverable resources” (i.e., not “unproved and discovered”). These shale oil plays are identified as the Eagle Ford; the Avalon and Bone Springs (within the Permian Basin); the Bakken; and the Monterey/Santos.

The Monterey/Santos play was estimated, according to the report, to contain 15.42 billion bbl of technically recover-able shale oil resources, amounting to around 64% of the total resources in the four shale oil plays examined. This estimate has generated significant interest, due to its vastness, particularly when weighed against current heated shale oil activity in the three other shale oil plays cited.

Overall US crude oil production has risen steadily since the month the report was issued, from a July 2011 average of approximately 5.6 MMB/D to a December 2012 average of 7 MMB/D. According to EIA monthly statistics, which are derived from a combination of estimates and actual data reported by federal and state agencies (with estimates supplanted by actual data as reported data gradually become available over time), increasing oil production in North Dakota (the Bakken) and onshore Texas (Eagle Ford and Permian Basin) drove the surge in overall US crude oil production.

Increased oil production stemming from the Monterey/Santos play has yet to materialize.
First IPTC in China Examines Future Upstream Opportunities
Authors: Donnelly John , Rassenfoss Stephen , Beckwith Robin
Published: February 2015

Conference review

The development of unconventional resources, China’s increasing importance on the global energy map, and turning E&P challenges into opportunities were among the topics discussed at the International Petroleum Technology Conference (IPTC) held 26–28 March in Beijing.

The first IPTC held in China officially opened with welcome addresses from the conference’s Executive Committee Cochairmen Zhou Jiping of China National Petroleum Corp. (CNPC) and Mark Albers of ExxonMobil, and from IPTC Chairman of the Board Mahmoud Abdulbaqi.

Zhou, who is president of CNPC and vice chairman and president of Petro-China, underscored the growing importance of both IPTC and China on the global energy stage. “IPTC has already become a highly influential conference in the oil and gas industry,” despite its relatively short history, he said. Of particular importance is IPTC’s collaboration across states, types of companies, and industry associations, offering a multidisciplinary approach to industry issues and challenges, he said. IPTC is organized by the American Association of Petroleum Geologists (AAPG), European Association of Geoscientists and Engineers (EAGE), Society of Exploration Geophysicists (SEG), and SPE.

Albers, senior vice president at Exxon Mobil, noted that “it is only fitting that IPTC take place in China” given the country’s rise to prominence on a global scale. More than 3,500 delegates from 65 countries attended the conference. More than 2,000 technical paper abstracts were received, the most in the history of the conference, which alternates between sites in Asia Pacific and the Middle East.

CEOs Examine Future Needs

When it comes to the future of the oil and gas business, all roads seem to lead to China. The country that is home to 1.6 billion people is a driver of global demand and is determined to be a partner in the worldwide search for the oil and gas and the new technology needed to continue expanding supplies, according to five chief executive officers who spoke at the CEO Plenary on the opening day of the conference.
Middle East Conference Focuses on Energy Future Key Enablers
Authors: Henni Abdelghani
Published: February 2015

Conference review

More than 2,000 oil and gas professionals from all over the world converged at the Bahrain International Exhibition in March to attend the 18th Middle East Oil and Gas Show and Conference (MEOS 2013).

Organized by SPE, the conference’s opening session presented a panel of high-ranking industry figures, who delivered their perspectives on this year’s theme, “Transforming the Energy Future.” The theme focused on current issues the oil and gas industry faces as it strives to meet future global energy demand with emphasis on the processes, technologies, business models, and human skills that will be required to meet those needs effectively and efficiently.

Delivering the keynote speech, H.E. Shaikh Ahmed bin Mohammed Al Khalifa, Bahrain Minister of Finance and Minister in Charge of Oil and Gas Affairs, said the theme of the conference was appropriate. “Transforming the energy future is well chosen as we live in an era where change is the norm and agility and proactivity mean the difference between success and failure,” he said.

Shaikh Al Khalifa said that the biggest challenge facing the industry is adapting to the accelerated rate of change that will propel the oil and gas industry into the future. “To adapt, we need to introduce new methods of thinking and new work processes to be able to meet the challenges faced by society in general and the energy sector in particular,” he said.

The game changers that will potentially have the most impact on the industry are unconventional resources, renewable energy, and energy efficiency, Shaikh Al Khalifa said. “One of the challenges facing the industry is the availability of skilled human resources. It is important that the industry ensure the continuous investment in human resources to supply the industry with adequate number of skilled engineers.”

Remarks during the executive panel session followed from Amin Nasser, senior vice president for upstream at Saudi Aramco; Martin Craighead, president and chief executive officer (CEO) at Baker Hughes; Paal Kibsgaard, CEO of Schlumberger; Sami Al-Rushaid, chairman and managing director of Kuwait Oil Company (KOC); and Sara Ortwein, president of ExxonMobil Upstream Research.
Q&A with Phil Andrews, CEO, Getenergy
Authors: Andrews Phil
Published: February 2015

Q&A

What is the mission of Getenergy?

Getenergy was originally created on the fringes of the Offshore Europe exhibition in Aberdeen in 2003. I was asked by the British government to run a meeting on education and training for 20 staff from national and international oil companies who were visiting the show. The meeting clearly demonstrated that the upstream industry desired a dedicated event entirely focused on education and training. Getenergy (Global Education and Training for Energy) was the company that emerged in 2004 following this discussion.

Getenergy was founded by accident, not design, based on a niche, yet clear, industry need. Getenergy does not provide or sell training; rather it is a platform for those who do, to meet the needs of those who require often complex training and education solutions, particularly in developing hydrocarbon provinces, where training is both part of the contractual obligation for IOCs and at the heart of the national economic development agenda.

Are most of your events designed to bring together NOCs, IOCs, academia, and the service sector?

Rather like preparing drilling muds, our meetings require all the right ingredients in the correct quantity. We seek, in every event, to have an equal number of universities, local colleges, training providers, and national and international oil and gas company representatives. We have a Learning Arena exhibition, which allocates space to exhibitors representing the world’s largest oil companies or the smallest university departments. In many of our meetings, universities from brand-new hydrocarbon provinces participate in what often represents the first international meeting they have attended.

You have an upcoming training event in London. What will the focus be? How is it unique? How many countries will be represented?

In addition to regional and national meetings Getenergy has, since 2005, organized an annual global meeting. This is really our flagship event, which has taken place in Houston (2005), Dubai (2006–07), London (2008–09), Kuala Lumpur (2010), Calgary (2011), and London (2012–13). The next global meeting is in London during 3–5 June and will see participation from those concerned with education, training, and technical learning delivery from 45 countries for 3 days of workshops, our Learning Arena Exhibition, and our “Power Point-free” Exchange sessions. We will have delegations from universities, institutes, and the oil and gas industry in Brazil, Ghana, Kazakhstan, Kurdistan, Malaysia, China, Mozambique, Nigeria, and Tanzania, among others. Our annual global event is unique not only in terms of audience, but also the detailed discussions among national and international oil and gas companies and the global education and training community that take place.
SPE/IADC Drilling Conference Highlights Industry Challenges
Authors: Parshall Joel
Published: February 2015

Conference review

The challenges of the drilling industry, technology advances, and the improvements needed to meet growing global oil demand in a safe, environmentally sound manner were the center of attention at the 25th SPE/IADC Drilling Conference held 5–7 March in Amsterdam.

A final attendance of 2,079 was the highest since the record level of 2,113 in 2007, a clear sign of the industry’s return to strength since the 2008–2009 global economic downturn. This year’s attendance was the second highest in conference history.

In 18 technical sessions, the conference covered a full slate of subjects including deepwater drilling; wellbore placement; drilling automation; early detection and well control; managed pressure and underbalanced drilling; and health, safety, and environment. A total of 102 papers were presented, selected from more than 350 abstracts, and there were 28 ePoster presentations. 

The exhibition featured displays by 128 organizations, providing attendees the opportunity to see and discuss the latest in equipment, services, and other resources supporting the global exploration and production industry. In addition, a Young Professionals luncheon featured keynote speaker Eric van Oort, Lancaster Professor in Petroleum Engineering at the University of Texas at Austin, who addressed “The Great Crew Change.”

Delivering Wells

“Delivering Wells in a Critical World” was the theme of the conference plenary session on 6 March. Moderator Ole Slorer, director of global oilfield services at Morgan Stanley Research, framed the industry’s challenge over the next 7 years. The drilling sector will need to bring on 27 million BOPD of new production to meet expected world demand by 2020, with most of the increase anticipated to come from fields already discovered. The biggest contributors will be deepwater fields, particularly those in ultradeepwater, and liquids-rich shale formations in North America, he said.

Environmental risk and rising costs will put increasing pressure on drillers, and projects will become more complex, Slorer said. In addition, the world’s floating offshore drilling rig fleet will need to expand from 300 today to about 500 by 2020. Is the industry “ready for this challenge?” he asked.
Mensa Field: Deepwater Gulf of Mexico Case Study
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 159741, ’Mensa Field, Deepwater Gulf of Mexico - Case Study,’ by Muhammad Razi and Peter Bilinski, Shell Exploration & Production, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed.

The Mensa field is a deepwater Gulf of Mexico (GOM) geopressured gas field, producing from Upper Miocene sand with faulted four-way closure. During the early life, pressures fell sharply, with the field performing as a dominantly depletion-drive reservoir. The trend indicated isolated compartments. After a few years of production, pressures leveled off significantly. This midlife trend seemed to be in contact with originally isolated gas compartments and an aquifer. The late-life pressure trend indicates aquifer influx that effectively blocked the main producing wells from a significant gas area and pressure support.

Introduction

The Mensa field is a deepwater GOM subsea development in Mississippi Can-yon (MC) Blocks 686, 687, 730, and 731 (Fig. 1). The field was discovered in 1987 with Well MC731-1, which penetrated 110 ft of net gas pay in the I sand. Appraisal Well MC730-1, drilled in 1988, penetrated 168 ft of net gas pay in the same sand.

On the basis of seismic interpretation and well information, the I sand was modeled as a thick high-net-/gross-pay-ratio (NTG) sand with 29 to 33% porosity, 250- to 1,000-md permeability, and a gas-in-place volume of up to 1.5 Tcf (Fig. 2). North/south-striking faults divide the main I sand into eastern and western fault blocks. The fault tips out to the south such that the fault blocks are in good pressure communication (confirmed later by depleted pressures recorded in Well A2). A basinwide aquifer was modeled in the south, with the original gas/water contact (GWC) set at 15,750 ft subsea. The I sand was assumed to produce by moderate-to-strong aquifer support.

The Mensa field faced many challenges.

Deep water (approximately 5,300 ft) resulted in high subsea-well and system costs.

Nearest facility was approximately 68 miles away (West Delta Block 143), involving high development cost to connect.

Low ultimate recoveries because of the almost flat structure (approximately 5° dip), large aquifer, and high-permeability sand (wells water out immediately after water breakthrough).

Poor economics because of the low condensate yield and low gas prices at that time (approximately USD 1.5/Mcf).

High subsea-intervention cost and long time required (e.g., wireline job, acid treatment, or workover/sidetrack).

High rock compressibility (30 to 60 microsip), which resulted in collapsed casing and sand-control issues.
Setting the Bear Free: Challenges of the Deepwater Ursa A-10 ERD Well
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163525, ’Setting Free the Bear: The Challenges and Lessons of the Ursa A-10 Deepwater ERD Well,’ by John Gradishar, SPE, and Gustavo Ugueto, SPE, Shell Upstream Americas, and Eric van Oort, University of Texas at Austin (formerly with Shell Upstream Americas), prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5-7 March. The paper has not been peer reviewed.

This case history presents the highly challenging extended-reach deepwater well, Ursa A-10, drilled in the Ursa (Latin for bear) prospect in the US Gulf of Mexico (GOM). This 30,000-ft well, drilled from the Ursa tension-leg platform (TLP) to a vertical depth of 18,000 ft and a horizontal displacement (HD) of 20,000 ft, targeted the Yellow sand in the Ursa/Princess section of the greater Mars-Ursa basin. During drilling of the original hole, a subsequent sidetrack, and two mechanical bypasses, several significant hole problems materialized that led to extensive nonproductive time. At least five independent borehole-failure mechanisms were encountered.

Introduction

In the aftermath of the tragic 2010 Macondo/Deepwater Horizon event, it is important that the industry share case studies on successful wells. It also is important to share information on wells that proved to be very challenging. Sharing learnings, best practices, and experiences on such wells will raise the overall level of proficiency in constructing these wells throughout the industry. As is often the case, more is learned from adversity than from outright success. This is the main reason that the Ursa A-10 case is presented.

Over the last decade, world-class extended-reach-drilling (ERD) wells have been drilled in the continued development of the Mars-Ursa basin in the GOM. These high-deviation wells are distinguished by depth [true vertical depth (TVD) greater than 17,000 ft], HD greater than equal to ;20,000 ft, and overall measured depth (MD) greater than equal to 30,000 ft. Challenges include a geopressured deepwater environment, complex casing programs, and special drilling issues.

The combination of these challenges makes the Ursa A-10 case noteworthy. ERD wells have been drilled to longer HD and overall MD, but those wells generally had simpler casing programs and a more-forgiving pore-pressure/fracture-gradient environment with associated drilling margins. Larger margins leave more room for such things as equivalent-circulating-density (ECD) and annular-pressure fluctuations, mud problems (such as barite sag and hole-cleaning and associated pack-off problems), accommodating manageable levels of borehole instability, and implementation of limited redesign philosophies.