bluuebunny/crossref_metadata_2025_split huggingface dataset:
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].”