bluuebunny/crossref_metadata_2025_split huggingface dataset:
Managed-Pressure Drilling To Counteract Lost-Circulation and High-Pressure-Gas Zones: South Wapiti Red Rock Field
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 137428, ’Successful Use of Managed-Pressure Drilling To Counteract Lost-Circulation and High- Pressure-Gas Zones: A Case Study From the Red Rock South Wapiti Field in Grande Prairie, Alberta, Canada,’ by Hassan K. Malik, SPE, Raymond J. Litwin, SPE, and Bernard C. Jones, ConocoPhillips Canada, prepared for the 2010 Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. The paper has not been peer reviewed.
Use of heavy mud weight (MW) to control high-pressure (HP) -gas and lost-circulation zones at the same time is a challenge. The Red Rock field in the South Wapiti area in Alberta experienced this combination, which resulted in high operational costs, primarily caused by an additional casing string, high MW, and severe mud losses. On average, costs were 20% higher than anticipated, making this drilling program uneconomical.
Introduction
The Red Rock field is in the Deep basin of western Alberta, where much of the gas is found in low-porosity, low-permeability reservoirs deposited in an epicontinental seaway. The Deep basin is unique in that porous rocks are water saturated updip to the east and gradually become gas saturated and less porous downdip to the west.
The Falher section (overlying the Gething formation) is overpressured in the area, but there is more confidence in predicting the presence on a broad scale. Coals are found throughout the Falher and Gething formations and must be considered. Historically, lost circulation has occurred in the Falher section at elevated MWs, also into several coal seams in a few cases. Recent wells have experienced kicks in the Bluesky, Gething, and Falher zones, which have driven MWs higher to manage risk. Further uphole, the Doe Creek and Dunvegan formations have been pinpointed as a main lost-circulation section in the area. Natural fractures exist in the wider area across this section, which supports the determination that these zones cause lost circulation.
Red Rock Drilling Challenges
Wells in this area are drilled with an invert-oil-based-mud (OBM) system, which is used in the field with consistent success in keeping reactive shales stable. The use of OBM systems, with high oil/water ratios, is costly in lost-circulation situations. Wellbore-strengthening materials have been used to varying degrees to mitigate losses while drilling the usual problem zones. This is seen when drilling into the Doe Creek and Dunvegan formations with low MWs (930–980 kg/m3) and losses are encountered. A regime of adding wellbore-strengthening materials before penetrating these zones helps heal the losses, and in several cases allowed the MW to be increased deeper in the well. This technique is an important tool in this area to drill through loss zones.
Technology Focus: History Matching and Forecasting (April 2011)
Authors: Cardoso Marco A. 
Published: February 2015

Technology Focus
History matching and forecasting of geologically complex reservoirs are challenging aspects for efficient reservoir management. The foremost reason is the high level of uncertainty that exists in the reservoir models because of the limited, sparse, and multiscaled reservoir data available. The problem is further heightened for deepwater provinces such as the Gulf of Mexico, Brazil, and West Africa.
The objective of the history matching is to adjust the geological model and its parameters (e.g., permeabilities and porosities) such that the simulation model is able to reproduce the well-flow-rate and pressure histories reasonably. The result of the history-matching process is a new simulation model that can be very different from the original geological model. However, this history matching is an inverse problem, meaning that there is no unique solution. Different arrangements of reservoir parameters can furnish many simulation models tuned to the available past data. Even though each matched reservoir model is capable of reproducing the observed data, these various geological models can generate different production forecasts. The greatest challenge is obtaining multiple efficient history-matched models for realistic uncertainty estimation.
Conventional history matching is a trial-and-error process. The mismatch between observed and simulated values is minimized by adjusting reservoir parameters over successive simulation runs. Even for experienced reservoir engineers, the process is very time consuming and, in general, a single adjusted scenario can be geologically inconsistent. On the other hand, modern history-matching techniques apply numerical optimization and generate multiple geologically consistent adjusted scenarios.
Most of the history-matching research work being carried out today can be classified into four types of algorithms: gradient-based methods, stochastic methods, data-assimilation approaches, and streamline techniques. Data-assimilation techniques, such as an ensemble Kalman filter, represent a very active research area, and new and potentially promising methodologies have been developed. The papers summarized in this feature and those in the additional-reading list provide good examples of new methodologies.
History Matching and Forecasting additional reading available at OnePetro: www.onepetro.org
SPE 129183 “A New Adaptively Scaled Production-Data-Integration Approach Using the Discrete Cosine Parameterization” by Eric Bhark, SPE, Texas A&M University, et al.
SPE 131627 “History Matching With Sensitivity-Based Parameter Modifications at Gridblock Level” by H. Almuallim, SPE, FirmSoft Technologies, et al.
SPE 141216 “History Matching a Field Case Using the Ensemble Kalman Filter With Covariance Localization” by Alexandre A. Emerick, SPE, Petrobras, et al.
Technology Focus: Natural Gas Processing and Handling (April 2012)
Authors: Hobbs George 
Published: February 2015

Technology Focus
In 2010, natural-gas reserves were approximately equivalent to 75% of the oil reserves (including oil sands). Unconventional gas sources continue to make up an increasingly important part of the natural-gas supply, particularly shale gas and coal-bed methane (CBM), which contribute approximately 40% to US natural-gas reserves.
Generally, very remote offshore gas reserves cannot be exploited economically by use of fixed subsea pipelines that tend to link the field with a specific geographical market. Operators can maximize market reach through natural-gas liquefaction and improved marine liquefied-natural-gas (LNG) tankers. For ultimate flexibility, four floating LNG-production facilities are predicted to come on stream within this decade.
Commercial exploitation of the known massive hydrate reserves probably is some time off; however, the chemistry research involved in hydrate management for current natural-gas production may accelerate progress in that area. Hydraulic-water reuse is key to the future of the CBM and shale-gas industries.
There are many opportunities to learn about and share natural-gas technologies. An SPE workshop, “Reducing Environmental Impact of Unconventional Resources Development,” will take place in San Antonio, Texas, 23–25 April 2012. A joint SPE/SEG workshop, “Injection Induced Seismicity,” will be held in Broomfield, Colorado, 12–14 September 2012. There will be an SPE “Tight Gas” workshop in Adelaide, Australia, 10–13 June 2012, and the SPE Unconventional Reservoir Technical Interest Group (TIG) provides a useful information exchange, as does the Gas Technology TIG. The 2013 SPE Unconventional Gas Conference and Exhibition will be held in Muscat, Oman, 28–30 January. The 2013 SPE International Symposium on Oilfield Chemistry to be held in The Woodlands, Texas, 9–13 April, includes topics on gas-processing chemical applications.
Acid-gas (CO2 and H2S) removal from natural gas and sequestration/recovery/disposal technologies are very important in exploitation of poorer-quality gas finds. Much work continues in this area, and very large acid-gas-removal units are in operation or are planned for the Arabian Gulf region.
Recommended additional reading at OnePetro: www.onepetro.org.
IPTC 15208 World’s First Demonstration Project of Natural Gas Hydrate Land Transportation by Tomonori Nogami, Mitsui Engineering and Shipbuilding, et al.
IPTC 14206 International LNG Prospects: 2011 and Beyond by Chau Tran, University of Houston, et al.
SPE 143019 Underground Natural-Gas Storage in the UK: Business Feasibility Case Study by Esther Escobar, University of Aberdeen, et al.
Improved History Matching and Uncertainty Characterization
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 141336, ’Combining the Ensemble Kalman Filter With Markov-Chain Monte Carlo for Improved History Matching and Uncertainty Characterization,’ by Alexandre A. Emerick, SPE, Petrobras, and Albert C. Reynolds, SPE, University of Tulsa, prepared for the 2011 SPE Reservoir Simulation Symposium, The Woodlands, Texas, 21-23 February. The paper has not been peer reviewed.
With the use of the ensemble Kalman filter (EnKF) for assisted history matching, the approximation of covariance matrices from a finite ensemble of states and a finite ensemble of predicted-data vectors can lead to a large underestimation of uncertainty in the posterior probability-density function (PDF) for the state vector. Regardless of whether covariance localization is used, EnKF can lead to an overestimation of the uncertainty in predictions of reservoir performance. Under reasonable assumptions, a Markov-chain Monte Carlo (MCMC) algorithm will, theoretically, generate a correct sampling of the posterior PDF conditional to dynamic data.
Introduction
In a reservoir-simulation study, history matching is essential to establish a measure of legitimacy of reservoir-performance predictions. Over the last decade, increased importance has been attached to quantifying uncertainty in reservoir-performance predictions and in reservoir description to manage risk. Because of this interest in characterizing uncertainty, it is common to generate multiple history-matched models. However, generating multiple history-matched models does not necessarily lead to a correct assessment of uncertainty. Uncertainty has no scientific meaning outside the realm of statistics and probability.
The MCMC process provides a theoretically attractive method for sampling the posterior PDF for reservoir-model parameters. MCMC does not require knowledge of the normalizing constant in the target PDF to be sampled. A properly designed MCMC method will sample the target PDF correctly in the limit as the number of states in the chain approaches infinity. However, for high-dimension problems, MCMC typically requires a large number of iterations to sample the target PDF correctly. When MCMC is used to estimate the posterior PDF of reservoir-model parameters conditional to observed production data, calculation of the probability of accepting the transition from the current state to the proposed state requires a run of the reservoir simulator to evaluate the likelihood portion of the posterior PDF. Therefore, the direct application of MCMC can be prohibitively expensive computationally for realistic reservoir cases.
In Search of Bigger, Stronger, and Lighter Ways To Open Paths for Oil Production
Authors: Rassenfoss Stephen 
Published: February 2015

Proppant Advances
There’s an old line in the proppant business that customers want a product that is stronger than diamonds, lighter than water, and cheaper than dirt. And they are serious about that.
The rapid shift to unconventional oil exploration and production has made creating and maintaining better pathways for hydrocarbon flow a priority. That requires bigger bits of sand or ceramic, made stronger to maintain openings longer, and lighter, so it can be pumped further into formations using less horsepower.
Delivering larger concentrations of bigger proppant requires viscous fracturing fluids. Some of this can be described as a return to conventional formulas, but the biggest category used now in US fracturing is hybrids—a range of options being tried to increase oil yields.
With current methods often leaving more than 90% of the oil behind in unconventional formations, there’s a powerful motivation to seek out new and improved methods to ensure greater fracture conductivity.
At the SPE Hydraulic Fracturing Technology Conference in February the buzz was around a totally different approach to keeping dense particles suspended in water. Rather than putting polymer gels in water to make it more viscous, each bit of sand or ceramic is given a coating that rapidly expands in water to about 5 times its original size.
The combination, called self-suspending proppant (SSP), is far less dense than its proppant core, but this is not like putting on a life jacket. When SSP is added to water, the result looks like a murky slurry, and feels like water. This is because SSP behaves differently than untreated proppant. When SSP is in water, each grain of polymer-coated proppant expands so it has much greater volume with far less density than the grain of proppant alone. Because of its properties, SSP takes up more space in water and also makes the water appear more viscous. Also, because SSP’s density is less than that of untreated proppant—but still greater than the density of water—its settling rate is dramatically less than untreated proppant, said Robert Mahoney, vice president in charge of research and development at Soane Energy, the chemical maker developing SSP in partnership with Marathon Oil.
He describes SSP under magnification as looking like a pile of fish eggs each with a dark spot in the middle surrounded by a clear layer.
Over the next year Marathon Oil will be testing it on a series of wells to see if replacing fluid thickened by gels with individually coated particles will deliver more proppant into the formation where it can maintain flow pathways for better results.
Middle East/North Africa Region Focuses on Tight Gas
Authors: Henni Abdelghani 
Published: February 2015

Conference review
As the era of the easy extraction of conventional hydrocarbon is over, energy companies across the world are tapping into difficult resources and developing unconventional reserves, such as shale gas and tight gas.
In the Middle East and North Africa region, results from recent gas exploration and appraisal activities indicate that the region holds substantial resources of unconventional gas, especially tight gas. Regardless of the existence of highly productive conventional gas fields in this region, tight gas-related exploration and appraisal activities in several countries in the region have increased and are expected to pick up pace going forward.
With this background, the SPE Middle East Unconventional Gas Conference and Exhibition (UGAS) was held in Oman to address the best practices and techniques used for the development of unconventional resources in the region. Under the theme “Unconventional and Tight Gas: Bridging the Gap for Sustainable Economic Development,” the conference highlighted the latest developments related to tight gas and shared success stories about the development of tight wells from regions all over the world. The 3-day conference highlighted the criteria, challenges, and environment required for successful unconventional gas production and how it implicates the long-term global supply of natural gas. Thirteen technical sessions along with poster and e-poster stations offered 90 presentations from more than 35 companies and 18 countries.
Delivering the keynote speech, Zaid bin Khamis al Siyabi, director general of oil and gas exploration and production at the Ministry of Oil and Gas in the Sultanate of Oman, said the Sultanate recently began searching for and exploring unconventional gas resources, and needs to make more natural gas available to local industries. “The importance of unconventional resources for the sultanate is really huge,” al Siyabi said.
Al Siyabi revealed that oil companies operating in Oman—such as Petroleum Development Oman, Shell, and BP—have drilled approximately 50 wells to explore unconventional gas resources using the latest technologies.
Darryl Willis, vice president resources, North American Gas, BP, said in his presentation titled “Development of Unconventional Resources: Past, Present and Future” that unconventional gas continues to be a journey of discovery and challenge. “The future of our industry is increasingly unconventional. In the US, about 40% of the gas comes mainly from shale gas,” Willis said.
The industry is now capable of producing gas from difficult geological structures at reasonable cost, making such resources economically viable, Willis said. “Among the success factors is the application of conventional techniques to unconventional, including the sweet-spot identification, integrated reservoir description, as well as the long-term development,” he said.
Announcement of SPE Board Nominees: 2015 SPE President and Slate of Directors
Authors: JPT staff _ 
Published: February 2015

SPE Board Nominations
Helge Haldorsen is the nominee for 2015 Society of Petroleum Engineers president. He and seven others make up the slate of Board nominees recommended for SPE Board positions by the society’s Nominating Committee and Board of Directors. These recommendations are based on nominations submitted via SPE’s online nominating process (see sidebar).
2015 SPE President
Helge Haldorsen is vice president–strategy and portfolio for Statoil Development and Production North America, based in Houston, Texas. He worked for Norsk Hydro in various roles, including chief reservoir engineer, vice president–technology and competence, vice president–exploration and research, senior vice president–international exploration and production, and president–Hydro Gulf of Mexico. Haldorsen has also held various engineering positions at British Petroleum, Standard Oil of Ohio (Sohio), and ExxonMobil (Esso). He was a second lieutenant in the Royal Norwegian Navy and professor of industrial mathematics at the University of Oslo.
Haldorsen earned an MS in petroleum engineering from the Norwegian Institute of Technology and a PhD in reservoir engineering from The University of Texas at Austin. He currently serves on the Offshore Technology Conference board of directors and the external advisory board for the Cockrell School of Engineering at The University of Texas at Austin.
Technical Director, Drilling and Completions
David Curry is a Baker Hughes technology fellow, based in London, UK. Prior positions with Baker Hughes include director of drill bit research and technical manager of drilling optimization. He has more than 25 years’ experience in drilling research and technology development, primarily related to drill bits and bit/rock interactions, and to drilling performance improvement. Before joining the oil industry he worked on nuclear power plant integrity.
Curry was named an SPE Distinguished Member in 2010. He is chair of SPE’s Research and Development (R&D) Advisory Committee, past chair of SPE’s R&D Technical Section, and has served on SPE’s Drilling and Completions Advisory Committee, Drilling and Completions Award Committee, and Books Development Committee. He was executive editor of SPE Drilling and Completion, and in 2007 was named A Peer Apart for peer reviewing more than 100 SPE papers. Curry has published more than 40 papers, been awarded eight patents, and coauthored one book. He earned an MA in natural sciences and a PhD in fracture mechanics, both at the University of Cambridge, and is a chartered engineer in the UK.
Advancing Industry Technology: A New Ecosystem for Innovation
Authors: Karanjikar Mukund , Pike William , Chitta Dolly 
Published: February 2015

Management
Over the past several decades, the upstream oil and gas industry has developed into a three-way structure consisting of operating companies, national oil companies, and service companies. In the absence of a major market need, such a triangular structure worked well enough to keep the industry functioning. As developing economies in countries such as China, India, and Brazil started to become major petroleum consumers in the early 2000s, crude oil prices began to skyrocket. The global oil supply and demand situation remains relatively tight (Fig. 1). Even today, the industry can barely meet peak demand of 90 million BOPD. The triangular structure now falls short of meeting market needs.
A large part of the problem is that all the easily available oil has been found and much has been depleted. Growth potential now is in unconventional oil, Arctic resources, and improved recovery factors in mature areas. Development of these petroleum resources requires innovative and cost-effective technologies. These technologies must also be safe and environmentally benign. While many of them are being, and will be, developed by the upstream industry, many more can, and should, leverage technological advances taking place in other industries. Technology transfer from other industries is not a new phenomenon. From time to time, the upstream industry has benefited from innovations in adjacent markets such as the military, medical, optics, and information technology sectors. For example, military technology developed during World War II played a large part in modernizing the upstream industry in the 1950s and later years.
Some of the innovations that migrated from military technology include shaped charges, gravity-based structures, and reeled pipelines and umbilicals. Shaped charges were adopted by the industry for use in tubular perforation and separation. Towed by the Allied forces from Britain, concrete gravity-based structures were flooded in place off the coast of France to serve as breakwaters during the Invasion of Normandy. Later, similar structures were used in the design of offshore oil production facilities. Reeled pipelines and umbilicals, used to supply fuel across the English Channel to Allied troops landing in Normandy, became the basis for the coiled tubing and umbilical techniques now used in oil-field operations.
More recently, nuclear magnetic resonance and digital core analysis developed in the medical and chemical fields respectively, have fostered technological advances in exploration and production. However, as significant as past technology transfer has been, it has occurred haphazardly. What is now needed is a more aggressive, organized system for the transfer of external technology into our industry. To create the ecosystem necessary to accomplish this, we first must honestly address a number of issues that impede technology transfer.