bluuebunny/crossref_metadata_2025 huggingface dataset:
IPTC Highlights the Importance of Technology and Collaboration in Unlocking Future Resources
Authors: Wilson Adam , Henni Abdelghani , Jacobs Trent
Published: February 2015

Conference review

Technology, research, and project best practices critical for producing the next generation of energy resources was the focus of panel discussions and technical paper presentations at the International Petroleum Technology Conference (IPTC), held 20–22 January in Doha, Qatar.

The seventh edition of IPTC attracted more than 6,000 attendees representing 523 companies from 63 countries, including top executives from both national and international oil companies. The largest multisociety, multidisciplinary oil and gas event in the Eastern Hemisphere, IPTC was hosted by Qatar Petroleum, with ExxonMobil as cohost. The conference was sponsored by SPE, the European Association of Geoscientists and Engineers, the Society of Exploration Geophysicists, and the American Association of Petroleum Geologists.

Andrew Swiger, senior vice president and principal financial officer for ExxonMobil and IPTC executive committee cochairperson, said that the event has become an important global forum for highlighting the research and innovation that will shape the exploration and production (E&P) industry’s future. The speakers and attendees at the event, agreeing that the era of easy oil is over, said that now is the time to deploy all technical capabilities to unlock future resources. The theme of the conference was “Unlocking Energy Through Innovation, Technology, and Capability.”

Qatar’s prime minister and interior minister, Abdullah Bin Naser Bin Khalifa Al-Thani, said during the conference opening ceremony that Qatar was eager to host and sponsor this event because of the importance of the energy sector in the prosperity and the development of the country. Meanwhile, Qatar’s minister of energy and industry, Mohamed bin Saleh Al-Sada, said that Qatar’s success in developing its natural resources and exploiting them wisely comes mainly from its long-term strategy that involved creating a well-developed infrastructure and a solid and diversified economy, as well as offering a stable investment climate.

A New Outlook

At ITPC’s plenary session, panelists described a world in which the conventional wisdom of yesteryear has been supplanted with a new outlook for the future, ushered in by a wave of new technologies. The speakers, representing six international and national oil companies, spoke about the challenges facing the industry with optimism based on the industry’s increasing success in tapping into complex resources to produce them safely and more efficiently.
Impact of the Big Crew Change on Employee Retention
Authors: Sprunt Eve , Howes Susan , Pyrcz Michael
Published: February 2015

Talent & Technology

You have invested a lot of time and money training new employees. Once employees are fully qualified, how do you retain them? The SPE Talent Council survey on factors affecting employee attraction and retention provides valuable insights. Documented in paper SPE 168112, the survey received responses from 1,737 people, and the results indicated that for those surveyed there are many important ways in which younger employees differ from older ones and that key retention factors differ with age.

Survey respondents were asked to rate 31 factors for staying with an employer and 31 factors for leaving an employer on a 6-choice scale that ranged from “most important” to “not at all important” and “not applicable.” Only people who reported having more than one employer were asked questions about leaving. Most of the survey respondents had worked for multiple employers (Fig. 1). Once people have experience switching employers, it may take less provocation or less enticement to persuade them to make another change.

For survey respondents, “golden handcuffs” were not very effective. “To qualify for a future benefit such as a pension or retiree medical coverage” ranked 15th out of 31 factors for staying for men over the age of 40, 22nd for women over age 40, and 26th for men and women under age 40.

Opportunity’s Siren Call

Opportunity was clearly the number one driver, but the results indicated the intensity of that driving force varies with age and gender. When people were asked to rate factors for leaving an employer, 53% of women and 49% of men under the age of 40 identified “insufficient opportunity, challenge, career potential” as “most important,” in comparison with 35% of women and 29% of men over the age of 40. When the question was worded “Why do you stay with an employer?” 53% of both men and women under age 40 identified “opportunity, challenge, career potential” as “most important,” in comparison with 39% of women and 32% of men over age 40.

Opportunity, while clearly of paramount importance, was only part of the answer. The top factor captures 7% to 8% of the “most important” responses for why survey respondents stayed, and 10% to 12% for why they left (Fig. 2). Capture of 50% of the “most important” responses for why survey respondents leave requires seven to eight factors. Capture of 80% of the “most important” responses for why people leave takes 15 to 16 factors. The results of this survey indicated that for companies to have attrition rates below 20% requires attention to many factors.
Defining Regions of Hydraulic-Fracture Connectivity Aids in Designing Completions
Authors: Wilson Adam
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 166505, ’Defining Three Regions of Hydraulic-Fracture Connectivity in Unconventional Reservoirs Helps in Designing Completions With Improved Long-Term Productivity,’ by Roberto Suarez-Rivera, SPE, Schlumberger; Larry Behrmann, Schlumberger consultant; Sid Green, SPE, Schlumberger and University of Utah; and Jeff Burghardt, SPE, Sergey Stanchits, Eric Edelman, SPE, and Aniket Surdi, Schlumberger, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.

Using large-scale hydraulic-fracturing experiments on tight shale outcrops, three dominant regions controlling stage production were identified—the connector between the wellbore and the fracture system, the near-wellbore fracture, and the far-wellbore fracture network. The particular nature of these regions may change depending on the play, the reservoir makeup, its relation to the in-situ stress, and the distribution of rock properties; however, these regions are always well differentiated. Understanding the role of each of these components in hydrocarbon production is fundamental to identifying the dominant sources of fracture-conductivity loss and accelerated production decline.

Introduction

Achieving economic production from nanodarcy-scale-permeability, organic-rich- mudstone reservoirs requires creating large surface area by hydraulic fracturing. More importantly, economic production depends on preserving the created surface area and fracture conductivity during long-term production. This paper is about understanding the surface area (fracture geometry) that is created in heterogeneous rocks with complex makeup, preserving the surface area after fracturing, and maintaining adequate fracture conductivity during long-term production.

Fig. 1 shows a conceptual representation of the interaction of the propagating fracture with weak interfaces and weak bedding as a function of distance from the wellbore. Branching and stepovers (not shown) also develop vertically, providing resistance to flow and to upward fracture growth. Three regions of fracturing with unique properties emerge from this concept: the wellbore/fracture connector, the near-wellbore fracture, and the far-wellbore fracture. The wellbore connector (possibly 10–30 ft) is the region of highest hydraulic convergence and appears to be a choking point for production. This is particularly so if it is not propped appropriately. The near-wellbore fracture is of limited extent (200–400 ft) and represents most of the propped surface area and possibly most of the produced hydrocarbons. Unfortunately, proppant transport in the far-wellbore fracture region is minimal; the created far-field surface area is easily lost and does not contribute to production. This loss of surface area at the farwellbore region may not be avoidable by operational changes at the wellbore.
Technology Focus: Production Operations (March 2014)
Authors: Alhanati Francisco J.S.
Published: February 2015

Technology Focus

Production engineers are facing a new challenge when trying to select optimal well-production systems (in particular artificial lift) for important, relatively new resources: liquids-rich shale and deepwater subsalt applications. They are being asked to make such a selection when there are still large uncertainties about the well productivity and the produced-fluids thermodynamics (i.e., unclear functional requirements).

These applications are overall quite different, and the reasons for the large uncertainties are not the same. On the other hand, both applications involve relatively deep wells and relatively high pressures and temperatures downhole and the associated complications. For both applications, one needs to try to select a system that is flexible, so that it can work properly in a relatively wide range of operating conditions; that is reliable, so that it does not require frequent interventions; and that is easily retrievable, so that there is no need to have an intervention with a full-size rig every time you have to replace a key part of the system. By the way, space is limited both in the casing downhole and in the tubing hanger (for extra penetrations); therefore, there is only so much you can install in the well to try to achieve all this.

The recent increased cost and decreased availability of high-capacity rigs have certainly provided extra incentive for the development of rigless deployment and intervention techniques. Nevertheless, further technology development is still required to make available production and intervention systems that meet the demands of these applications.

Meanwhile, what is a production engineer to do? The best approach will depend on the business drivers for the operator, in particular the right balance between shortand long-term goals. Some solutions may require a lower capital investment or allow for higher production rates initially but at the cost of a lower overall recovery from the reservoir in the long term. If the focus is on long-term reservoir recovery, the best approach likely will involve a higher capital investment and lower production rates (and lower drawdowns), at least initially. JPT

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

SPE 166177 Completion and Production Strategies for Liquids-Rich Wells in Ultralow-Permeability Reservoirs by Amit Kumar, Halliburton, et al.

SPE 166027 Decision Analysis of Long-Term and Short-Term Production Optimization Applied to the Voador by Agus Hasan, Norwegian University of Science and Technology, et al.

SPE 166379 A Case History: The Installation of a System To Restore Full Safety-Valve Functionality to a Malaysia Offshore Well With a Damaged Control Line by M.K.M. Aminuddin, Petronas, et al.
Improved Recovery Rate in Subsea Wells by Use of Riserless Light Well Intervention
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24367, ’Improved Recovery Rate in Brownfield Subsea Wells Using Riserless Light Well Intervention,’ by O.E. Karlsen, SPE, B. Morrison, SPE, and P. Maciel, SPE, Welltec, prepared for the 2013 Offshore Technology Conference Brasil, Rio de Janeiro, 29-31 October. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.

The number of subsea wells has increased steadily to more than 5,500 by the end of 2012. Unfortunately, because of their location in deep water, interventions in subsea wells have typically required drilling rigs, and operators have been reluctant to perform interventions on these wells. Cost-effective riserless light well interventions (RLWIs) are crucial if subsea operators are to realize the full potential of 50% oil recovery (or more) from their subsea fields.

Introduction

Traditionally, subsea intervention has required a deepwater drilling rig to be freed from the drilling schedule and mobilized to the subsea wellsite. Then, a riser is connected to the subsea well, allowing electric-line, coiled-tubing, or heavier pipe-conveyed interventions. These types of operations are challenging to schedule, time consuming, and costly and can have high risk. With this combination of factors, operators often decide that costs and potential risks of an intervention to improve production are too high and choose to forgo this work on an adequately producing well with no operational problems. Thus, recovery factors in subsea wells are much lower compared with recovery rates of dry-tree, platform-based wells.

RLWI

RLWI is run from smaller, dynamically positioned light-well-intervention vessels instead of large workover ships. RLWI reduces costs and improves scheduling flexibility, thereby reducing barriers to performing subsurface well interventions and helping subsea operators improve recovery rates.

The key to the low cost of RLWI is that the subsea well-control package (or “subsea stack”) is deployed subsea as a single lift. Once landed on the subsea tree, wireline tools are deployed in a subsea lubricator through open water from the vessel down to the subsea stack. The electric line runs through the open water rather than inside a riser from the surface. On top of the lubricator pipe, a pressure- control head is connected to avoid spills. Fig. 1 shows the combination of technology and services used to perform an RLWI.

In addition to eliminating rig-rental costs, mobilization and rig up/down is faster, and thus the intervention process naturally has less nonproductive time. The ease of operations and light weight of the equipment provide a further cost savings because fewer people are needed. One intervention study showed that RLWI was accomplished at 50% of the cost of conventional interventions.
The Evolution and Potential of Networked Pipe
Authors: Hernandez Maximo , Long Roy
Published: February 2015

Technology Update

The need for “next-generation” technology for improved data transmission up the hole in drilling operations has been acknowledged for more than 2 decades. The term “next generation” typically implied a quantum leap in transmission speed from that available, by means of current state-of-art telemetry. That need is now filled by networked drillpipe (Figs. 1 and 2). Development of the technology began in 1997. Initial R&D addressed two problems, the growing need for a high-rate data-communications system that would allow high-resolution downhole drilling information to facilitate informed drilling decisions in real time and the attendant need to bring data-transmission rates to up to five orders of magnitude from mud-pulse telemetry’s approximate high of 10 bits per second.

Evolution of Networked Pipe Networked pipe had its genesis in a program undertaken by Novatek in 1997 to develop a mud-actuated hammer and a unique hammer bit. The company proposed to develop a set of complementary technologies integrated into the mud hammer that would enable various functionalities of the bit, including: 1) downhole bit rotation, 2) sensing and control, 3) data transmission, and 4) directional-drilling capability.

In the case of data transmission, the company concluded that a much higher data bandwidth was needed by the oil and gas industry than could be delivered by either existing mud-pulse telemetry or a new hammer acoustic-telemetry system. This was particularly true when considering the need for real-time data to support seismic while drilling (SWD), another possible offshoot of the hammer development. With this conclusion in mind, other acoustic sources with higher frequency ranges than the hammer were investigated. Substantial project focus was directed to this area of R&D, as it was deemed to be a critical enabling technology for the rest of the drilling system under development.

Initial development focused on the use of acoustic transmissions to carry high-frequency data through a single length of standard drillpipe. Data-rate limitations led to the abandonment of the concept and to the investigation of wired pipe that transmitted data across the tool joints using high-frequency acoustic transducers. However, the need for electric power and electronic support for each transducer, and the need for timing of the threaded connections when made up, led to the abandonment of that approach also. The company then directed its focus to fundamental work performed with a high-efficiency inductive-coupling sys-tem that looked promising. That technology resulted in networked drillpipe.
Presalt Propels Brazil into Oil's Front Ranks
Authors: Parshall Joel
Published: February 2015

In an industry whose scale and character have arisen so much from great discoveries of vast fields, the recent oil discoveries in the deepwater presalt layers off Brazil could rank as some of the biggest, most important globally in several decades.

At the center of the expansive presalt play is Petrobras, the Brazilian national oil company, which operates most of the concession acreage that has been awarded and has drilled most of the discoveries. With the discoveries made in the presalt, Petrobras President Sergio Gabrielli has said Brazil will rise to eighth place in oil and gas reserves among the world’s producing countries. Based on current rankings, this would place it above Nigeria and below Venezuela. To optimize the development of the presalt, a host of major challenges—geological, engineering, commercial, and financial among them—will need to be met.

Until the discoveries of 2007–09, there had been little drilling in Brazil’s presalt structures for many years. A number of shallow-water presalt discoveries had been drilled and developed in the Campos Basin during the 1970s and 80s. However, giant discoveries in post-salt reservoirs at that time shifted most attention toward those strata. Major questions remained about the suitability of presalt targets and the risks of drilling through salt layers as thick as 6,600 ft. The difficulties of seismic imaging beneath salt also were a considerable barrier, not to mention the challenges of deepwater drilling and development pertaining to some potential future targets.

Over the following 10 to 15 years, however, the industry’s deepwater capabilities progressed, along with the realization that the largest remaining prospects lay in deeper and deeper waters. In bidding rounds during 2000–01, Petrobras acquired a cluster of deepwater and ultradeepwater presalt leases in the Santos Basin—acreage that in total was larger than the entire Campos Basin to the north. The company then launched one of the largest seismic programs in industry history to image and interpret the geology of the lease acreage.
Technology Focus: Offshore Drilling and Completion (April 2010)
Authors: Jousseaume Jean-Louis
Published: February 2015

Technology Focus

After a high-activity and high-oil-price period, we again entered into a low phase of the cycle in which reducing costs becomes our priority. Meanwhile, we still must deliver barrels and wells, in due time, keeping employees safe and healthy, and without any damage to the environment. Consequently, we are obliged to intensify efforts to innovate and try new concepts, either to access prospects that were technically not possible just a few years ago or to increase recovery from mature and declining fields without spending excessive amounts of money.

But we should keep in mind that technical progress is not the only path to improve our global and economic performances. Such an improvement should include an established process of questioning all our practices, including but not limited to:

Adapted personnel management—because at the end of the day, the quality of the deliveries is linked closely with the training and knowledge of the employees running the job

Contractual changes that establish win-win relationships between the parties—it is always useful to remember that a good contract is a contract making both parties happy

Working transversely throughout all companies and contractors to establish and generalize commonly agreed on standards and best practices

The following summaries and additional reading suggestions provide good examples of our constant research of new technologies. But our scope of work is much larger, and every improvement in every aspect of our job will help us to push away this decline of our industry that some prophets foresee; it is not closer today than it was 10 or 20 years back.

Offshore Drilling and Completion additional reading available at OnePetro: www.onepetro.org

OTC 20295 • “SBOP Drilling Enables Efficient Drilling in Extreme Water Depths” by Michel Dib, Intecsea, et al.

IPTC 13142 • “Anticollision and Risk Management Offshore Qatar: A Successful Collaboration” by Benny Poedjono, SPE, Schlumberger, et al.

OTC 20277 • “Moho Bilondo—The First Deepwater Development Offshore the Republic of Congo” by Claude Cahuzac, Total, et al.
Technology Focus: Natural Gas Processing and Handling (April 2010)
Authors: Vitucci John
Published: February 2015

Technology Focus

Industry forecasts continue to cite demand for natural gas as one of the fastest-growing hydrocarbon demands over the next 20 years. Demand for natural gas will challenge our industry to provide gas from conventional and unconventional gas supplies as well as from remote locations such as deepwater areas and the Arctic region. It also will require development of liquefied natural gas (LNG) and other transportation methods to link end-user markets with supply globally. In reviewing papers for this feature, the number of natural-gas transportation papers far outnumbered papers from other natural-gas technology areas and the number of papers for LNG far outnumbered other types of transportation-technology papers. LNG continues to gain momentum as a preferred method to commoditize natural gas on a global basis.

LNG projects are technically complex and require large long-term investments and a multidisciplinary engineering approach for successful execution. The Qatargas-2 LNG project illustrates the complexity and large number of engineering and technical disciplines required of an LNG project: well-completion designs that provide sustained deliverability over the life of the facility; process designs incorporating new liquefaction technology, advanced power-generation designs, improved efficiency, and cleaner emissions; and LNG carriers that continue to push single-ship transport volumes ever higher while meeting strict safety and environmental standards. Such projects require large efforts from a broad spectrum of engineering disciplines, technical specialties, and project management. They provide for some of the most technically challenging work found in the industry today.

The papers highlighted in this feature and the suggested readings merely scratch the surface of LNG and other alternative-gas-transportation technologies. Regardless of technical discipline, I am confident there is a technical topic here that each reader will find touches upon his/her area of expertise.

Natural Gas Processing and Handling additional reading available at OnePetro: www.onepetro.org

OTC 20048 • “LNG STS Operations in Arctic Waters” by Tor Einar Berg, Marintek, et al.

SPE 120745 • “Economics of LNG Projects” by Faleh T. Al-Saadoon, Texas A&M University–Kingsville, et al.

IPTC 13707 • “Qatargas-2—Leading the Way in Clean LNG-Train Technology” by M.D. Pratt, Qatar Liquefied Gas, et al.

OTC 20145 • “Marine CNG—Why Hasn’t It Happened?” by C. Young, Centre for Marine CNG, et al.
Accurate Gas-Viscosity Correlation for Use at HP/HT Conditions Ensures Better Reserves Estimation
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 124734, ’More-Accurate Gas-Viscosity Correlation for Use at HP/HT Conditions Ensures Better Reserves Estimation,’ by Ehsan Davani, SPE, Kegang Ling, Catalin Teodoriu, SPE, William D. McCain Jr., SPE, and Gioia Falcone, SPE, Texas A&M University, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October.

High-pressure/high-temperature (HP/HT) gas reservoirs have pressures greater than 10,000 psia and temperatures higher than 300°F. Modeling the performance of these reservoirs requires understanding gas behavior at elevated pressure and temperature. Gas viscosity is used to model the gas mobility in the reservoir and can have a significant effect on reserves estimation during field-development planning. Accurate measurements of gas viscosity at HP/HT conditions are extremely difficult. Public-domain databases of hydrocarbon-gas viscosity were reviewed for validity of gas-viscosity correlations and their applicability range.   

Introduction

The growing demand for natural gas is driving the search for new deeper sources of gas, many of which encounter HP/HT conditions. Among gas properties, viscosity is seldom measured in the laboratory and, typically, is estimated by use of correlations. At HP/HT conditions, reservoir fluids will be very lean gases, typically methane with some level of impurity, and therefore the gas properties may be different from those of gases at lower pressures and temperatures.

A review of large databases of published viscosity data for pure methane and mixed hydrocarbons revealed limitations in terms of experimental conditions, data quantity, and in some cases accuracy. The full-length paper details many of these limitations. A review of available gas-viscosity correlations also was performed, which showed that these correlations were developed from experimental data taken at low-to-moderate pressures and temperatures and that their applicability at HP/HT conditions could be limited.

Available Correlations

National Institute of Standards and Technology (NIST). NIST developed computer software to predict thermodynamic and transport properties of hydrocarbon fluids. The software program uses the principle of “extended corresponding states” and was developed from pure-component and mixture data. The maximum pressure and temperature that can be used in the program are 44,100 psia and 1,340°F, respectively. The NIST gas-viscosity values closely match most of the published data, and the predictions generally are reliable for HP/HT conditions in the absence of real HP/HT gas-viscosity measurements.

Lee, Gonzalez, and Eakin (LGE) Correlation. The LGE correlation is based on measured data of pure-component gases and eight natural gases with specific gravities less than 0.77. The correlation can be used to estimate gas viscosity, provided that the molecular weight and density at the relevant conditions are known.
Comments: Iraq On The Rise
Authors: Donnelly John
Published: February 2015

Editor's column

Despite political and infrastructure hurdles, oil production from Iraq is on the rise. Output has reached 2.6 million b/d, the highest total since the US invasion in 2003.

The increase in production is coming from new projects begun by major operators over the past two years. The government has held three bidding rounds in the past two years, auctioning off more than a dozen oil and gas fields. Now it is contemplating another round later this year. Blocks in the southern, northern, and western parts of the country will be offered. The south is by far the largest producing region.

Total oil production now stands at approximately 2.6 million b/d and three fields currently under development could add another 500,000 b/d to output by the end of this year. Production began rising last year, as companies that won fields in a 2009 auction began drilling, primarily in the southern part of the country. Companies are optimistic about increasing output this year. BP already has increased production at the Rumaila field from 1.06 million b/d to 1.28 million b/d, Eni has increased output at the Aubair field from 148,000 b/d to 270,000 b/d, and ExxonMobil plans to boost output at the West Qurna 1 field 50,000 b/d to 280,000 b/d.

At the recent Iraq Oil & Gas Summit in Houston, former Iraqi Deputy Minister of Oil Abdul Jabbar Al-Waggaa said activity by operators and service companies in the country was growing despite legal questions about some of the contracts signed. He advocates the creation of an Iraqi national oil company that would renegotiate the upstream contracts that the government has signed with operators. Iraq has the potential to be producing 7 to 8 million b/d in a decade, he said, although the country’s stated goal is to increase production to 12 million b/d by 2017.

Most estimates are less optimistic. A report by analysts at Bank of America Merrill Lynch predicts that production will hit 4.4 million b/d by 2015. The Center for Global Energy Studies forecasts output of 4 million b/d by 2018. And the International Energy Agency sees 4.8 million b/d by 2020. These reports note the huge constraints on the current infrastructure system of pipelines, storage, and export facilities and political uncertainty rather than the potential of Iraq’s oil fields. Regardless of the rate of increase, the key issue of how other OPEC members will react to new production entering the market must be addressed, Mussab Al-Dujayli, a former official with Iraq’s oil ministry, told the Houston gathering.

Most of the oil increase appears to be heading for Asia, especially Japan, China, and India. Asia is expected to receive just less than 1.1 million b/d of exports this year, almost half of Iraq’s crude exports of 2.4 million b/d. Although oil has been the focus of development so far, Heritage Oil announced a major gas discovery in the Kurdistan region in January. The company estimates reserves of between 6.8 and 9.1 Tcf. More drilling will take place later this year.
GOM Deepwater Field-Development Challenges at Green Canyon 468
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 137220, ’GOM Deepwater Field Development Challenges at Green Canyon 468 Pony,’ by M.H. Weatherl, Hess Corporation, originally prepared for the 2010 SPE Deepwater Drilling and Completions Conference, Galveston, Texas, 5-6 October. The paper has not been peer reviewed.

The deepwater Gulf of Mexico (GOM) has proved in recent years to be one of the most prolific oil-production provinces in the world. The bulk of the new reserves and production in this area flow from subsalt, Miocene reservoirs. In the summer of 2005, the Green Canyon 468 “Pony” discovery well was drilled. Information collected during appraisal drilling provided significant insight into subsalt oil reservoirs that exist in this area at depths between 28,000 and 31,000 ft true vertical depth (TVD).

Introduction

The Pony area currently consists of Green Canyon Blocks 468 and 469, approximately 175 miles south of New Orleans in 3,500 ft of water. The field is within a 30-mile radius of numerous discoveries and established production from fields including Genesis and Brutus to the north and Tahiti, Holstein, and Shenzi to the south and east.

From a well-construction perspective, Pony is characterized by geologic complexity and numerous design challenges. Many aspects of well design are common among 30,000-ft-plus-TVD GOM subsalt plays. However, one differentiating feature of this field is the severity of the subsalt pore-pressure/fracture-gradient regression. The area is characterized by a very thick salt section that ranges between 16,000 and 18,000 ft of total vertical thickness across the structure. Pore pressure ranges from ±15 lbm/gal mud weight equivalent (MWE) at the base of salt at 22,000 ft TVD to less than 10 lbm/gal MWE in the deepest pay interval near 31,000 ft TVD.

Exploration vs. Production Well

The majority of wells drilled to date in the deepwater GOM are exploration and appraisal. Furthermore, the necessary evolution of well design and increased complexity moving from an “expendable” exploration well to a “keeper” production well are under-stood fully by only a relatively few operators with firsthand experience. Fields with development wells with the level of complexity analogous to that found at Pony are very few (Fig. 1).

During exploration and early appraisal drilling, extremely high well cost can result in the challenge of balancing the need for additional appraisal drilling with controlling high presanction costs. A classic issue in an area such as Pony where exploration and appraisal wells exceed USD 100 million each is the recurring question, “Can we keep this well as a producer if we find pay?” The usual answer, which can be a source of contentious debate, is “probably not.” The rational behind this conclusion can be addressed best in the form of a business proposition.
Technology Focus: Natural Gas Processing and Handling (April 2011)
Authors: Hobbs George
Published: February 2015

Technology Focus

The 2009 reserves of natural gas were approximately equivalent to 82% of the oil reserves, yet gas consumption was only approximately one-fifth of oil consumption. With its relative abundance, clearly, natural gas will continue as an important energy source for some time, as emphasized by the current focus on unconventional gas sources, such as coalbed methane (CBM), shale gas, tight gas, and even potential hydrate production.  Even conventional large offshore reserves are developed more economically by use of floating liquefied-natural-gas (LNG) compression instead of onshore compression and very long subsea pipelines. Water handling and reuse is key to the future of the CBM industry, which is progressing toward LNG export. There are shale-gas workshops in Palos Verdes, California (11–12 April) and in Beijing (29 May–1 June) and an unconventional-gas workshop in Sapporo, Hokkaido, Japan (10–14 July). SPE has an Unconventional Reservoir Technical Interest Group (TIG), which is a useful information exchange, as is the Gas Technology TIG.

Other key high-volume gas sources that are only now able to be more fully exploited include highly-sour-gas production, which has many challenges in hydrate inhibition and sour-gas removal.  There is a Forum on sour gas in Bali (8–13 May). Much research has gone into low-dose kinetic hydrate inhibition in the last decade, and the next phase will be recovery and reuse of the valuable inhibitors. The 2011 SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas (11–13 April) highlights progress in gas-processing-chemical applications.

Natural Gas Processing and Handling additional reading available at OnePetro: www.onepetro.org

SPE 131160 “The Use of Huff-‘n’-Puff Method in a Single Horizontal Well in Gas Production From Marine Gas-Hydrate Deposits in the Shenhu Area of the South China Sea” by Gang Li, Key Laboratory of Renewable Energy and Gas Hydrate, et al.

SPE 133975 “CO2 Storage in Saline Aquifers: Design of a Demonstration Project To Dispose of CO2 Associated with Natural-Gas Fields in the South China Sea” by L. Zhang, SPE, China University of Petroleum (East China), et al.

SPE 131663 “Hydrate Formation: Considering the Effects of Pressure, Temperature, Composition, and Water” by J. Rajnauth, SPE, Texas A&M University, et al.
CO2 Storage as Hydrate in Depleted Gas Reservoirs
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 137313, ’CO2 Storage as Hydrates in Depleted Gas Reservoirs,’ by O.Y. Satsepina, University of Calgary, and M. Pooladi-Darvish, SPE, Fekete Associates, originally prepared for the 2010 Canadian Unconventional Resources and International Petroleum Conference, Calgary, 19-21 October. The paper has not been peer reviewed.

The full-length paper presents a study of the carbon dioxide (CO2) hydrate storage capacity of depleted gas pools. The effect of the in-situ gas in formation of mixed-gas hydrate; the effect of temperature increase as a result of the exothermic reaction of hydrate formation; the effect of initial reservoir pressure, temperature, and porosity; and conditions for avoiding the deleterious formation of hydrates around the well-bore are studied.

Introduction

Approximately 725 Mt of CO2 was emitted to the atmosphere in Canada in 2000, with more than 80% from combustion of coal, petroleum, and natural gas. CO2 is a greenhouse gas, so its capture and storage to avoid accumulation in the atmosphere are important components of climate-change mitigation. Safety issues are vital in choosing a geological formation in which to store CO2 because its sudden release poses danger not only to the environment but also to human life. Therefore, a low probability of CO2 leakage and an effective/efficient trapping mechanism are of great significance in choosing a storage site.

Sequestration of CO2 in the form of hydrate is quite attractive. Hydrates are solids composed of a framework of water molecules with gas molecules captured within the framework. As a result, storing CO2 in the form of hydrate provides a solid structure and a high density. Gas hydrate forms at conditions of high pressure and low temperature, which easily could be found in the deep ocean or in its sediments. Furthermore, researchers are studying sequestration of CO2 through replacement of methane (CH4) by CO2 in the hydrate structure when CO2 is injected into a hydrate reservoir at the appropriate conditions.

When CO2 is injected into a reservoir where methane is present, mixed-gas hydrates form. The stability conditions of CH4/CO2 hydrates are different from those of either CH4 hydrate or CO2 hydrate. The work presented in the full-length paper used a reservoir simulator that is capable of handling compositional processes and reactions with deviation from equilibrium that are used in modeling mixed hydrate. The simulator has been used previously to predict dissociation/formation of CH4/CO2 hydrate.

Results

In the Results section, hydrate formation in a single block is studied first. The model considered acts as a uniform cell and eliminates variations in pressure, temperature, and composition with space. An isothermal approximation is considered as a first step. This is followed by nonisothermal modeling of a single-block model, before proceeding to reservoir modeling.
Technology Focus: HP/HT Challenges (April 2011)
Authors: Payne Mike
Published: February 2015

Technology Focus

HP/HT operations remain a high interest for the industry as deeper reservoir plays are pursued around the globe. Deeper horizons inherently create trends toward higher pressures and higher temperatures, adding to the complexity that the increased loads of such deep targets entail. Addressing these challenges requires careful engineering practices and attention to detail.

The industry has an extensive and successful track record in dealing with HP/HT developments with 15-ksi systems introduced in 1957, 20-ksi systems in 1972, and 30-ksi systems in 1974. Ensuring that lessons learned and technical outcomes of HP/HT projects are accumulated over many years of industry activity is a pivotal area of focus for current industry personnel. Additionally, advances in computational capabilities, materials science, nondestructive testing, seal technologies, and wellbore and component simulation all bring further measures for integrity assurance that extend and fortify earlier engineering approaches to HP/HT developments.

Industry standards also play an important role to ensure that HP/HT exploration and development projects are accomplished in a safe and reliable manner. To this end, focused work groups within standardization organizations including the American Petroleum Institute and the International Organization for Standardization have been developing guidance standards for the next generation of HP/HT developments. The industry continues to make firm strides in the development and qualification of next-generation HP/HT equipment including the industry’s first 20-ksi, 18¾-in. subsea-wellhead systems and the industry’s first 20-ksi, 18¼-in. blowout preventer.1 In parallel with these surface- and mudline-equipment advances, downhole drilling systems are being advanced in notable ways. Through a collaborative agreement between major operators and a major service company, downhole drilling systems are being developed with objectives including an operating rating of 450°F and a survivability rating of approximately 500°F.

Finally, in terms of heavy-load handling and the deep-drilling aspects of HP/HT, leading drillpipe manufacturers now can provide metallurgies up to 165 ksi to address high-tensile-strength-design requirements. Across many fronts, substantial advances have been made and continue that provide the basis for the industry to address the next generation of HP/HT developments successfully.

HP/HT Challenges additional reading available at OnePetro: www.onepetro.org

SPE 138957 “It Is All About Pressure: Drilling a High-Pressure Well in Record Time Using Real-Time Tools” by Gustavo Santos, Ecopetrol S.A., et. al.

SPE 136884 “Ensuring Well Integrity in HP/HT Wells: Brunei Case Study” by Salim Taoutaou, SPE, Schlumberger, et al.

SPE 130716 “Material Selection for HP/HT Developments” by J. Marsh, Wood Group Integrity Management, et al.

1 Whitby, M.F. and Kotrla, J.E. 20-ksi BOP Stack Development. Paper 128477 presented at the 2010 IADC/SPE Drilling Conference and Exhibition, New Orleans, 2–4 February. doi: 10.2118/128477-MS.
Spectrum: SPE Strategic Plan - Mission Critical
Authors: Thakur Ganesh
Published: February 2015

President's column

To collect, disseminate, and exchange technical knowledge concerning the exploration, development, and production of oil and gas resources, and related technologies for the public benefit; and to provide opportunities for professionals to enhance their technical and professional competence.

In my January column, I talked about the amazing growth of SPE—doubling our membership in the past 10 years. This growth is not only a testament to the evolution of our industry and the high demand for knowledge sharing, but also to SPE’s ability to remain relevant to industry professionals. As we work to remain relevant, we keep our SPE Mission always in the forefront. What does the Board do to sustain that relevance and our focus on mission?

For a number of years, we guided the society using a series of Long Range Plans that were pinned to 10-year periods. But when it became evident that the rate of change and the need for responsiveness always outpaced the Long Range Plans—for example, things we thought would take 10 years were accomplished in 5 years—the Board decided we needed an evergreen Strategic Plan. The first Strategic Plan was introduced in 2008.

Our Board committees review the Strategic Plan annually to refine the plan, make course corrections, develop tactics and activities for implementing our goals and objectives, and provide guidance to our many standing committees that are responsible for carrying out key programs. Here are some of the initiatives the Board committees have identified for 2012 to support Strategic Plan objectives.

The Board Committee on Education and Professional Activities is responsible for the Strategic Plan elements of industry image; resource/reserves definitions, classifications, and guidelines; life-long learning and maintaining competence; and support of academia. Some of the challenges affecting these programs are unequal educational opportunities in different areas of the world, need for a more global and mobile workforce, and inconsistent adoption of new technology. The committee has identified the following objectives for this year:

Expand the offering of training courses

Expand our energy education efforts

Develop best-practice guidelines in key areas

Increase the global reach of the Ambassador Lecture Program, in which young professionals provide university students views on E&P careers

Further integrate young professionals into SPE
Under Pressure: Diving's Impact on the Offshore Petroleum Industry
Authors: Beckwith Robin
Published: February 2015

Diving technology

An intricate dance between developments in diving and in the offshore oil and gas industry has been under way since the industry’s beginnings. This can be traced back to 1897 when the first oil wells were drilled into the seabed from specially constructed wharves a few feet from the shore of a small California community called Summerland, 5 miles east of Santa Barbara. The number of wharves extending up to 25 ft from the shore grew, each with 6 to 20 wells. Sometime before 1911, Albert Christie was hired to conduct dives on the wharves—possibly the first time in history when a diver was involved in the search for oil and gas.

According to Christopher Swann, in The History of Oilfield Diving, “To a considerable extent, the history of oilfield diving is the history of modern diving as a whole.” He remarks that, “Today, nearly all work done under water, whether with divers or robots, is carried out using equipment and techniques developed to meet the requirements of the offshore oil [and gas] industry.”

Diving itself likely goes back eons, as humans learned to plunge into bodies of water for fish or items, such as pearls or sponges, which they came to value. As various sea-going vessels were developed, such as human-powered galleys used by the Phoenicians, which pushed human geographical limits through a maritime trading culture that spread across the Mediterranean from 1550 BCE to 300 BCE, it stands to reason that when shipwrecks occurred, people would seek to salvage treasure like precious metals or jewels from the ocean depths. A mid-second century inscription found at Ostia, the port of ancient Rome, refers to a guild of divers, corpus urinatorum, who were employed in the construction and maintenance of bridge and harbor foundations. In a paper published in 1976 in the American Journal of Philology, classical archaeologist John Oleson writes, “Salvage diving was frequent enough in the Roman world to require the definition of property rights in the Digest [of Roman law].”