bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Plains CO2 Reduction (PCOR) Partnership: CO2 Sequestration Demonstration Projects Adding Value to the Oil and Gas Industry
Authors: Gorecki Charles D. , Steadman Edward N. , Harju John A. , Sorensen James A. , Hamling John A. , Botnen Lisa S. , Ayash Scott C. , Anagnost Katherine K. 
Published: May 2016

Abstract
Carbon capture, utilization, and storage (CCUS) in geologic media have been identified as an important means for reducing anthropogenic greenhouse gas emissions into the atmosphere (Bradshaw et al., 2006). Several geologic settings are appropriate for geologic storage of carbon dioxide (CO2), including depleted oil and gas reservoirs, deep brine-saturated formations, CO2 flood enhanced oil recovery (EOR) operations, and enhanced coalbed methane recovery. The U.S. Department of Energy (DOE) is pursuing a vigorous program for demonstration of CCUS technology through its Regional Carbon Sequestration Partnership (RCSP) Program, which entered its third phase (Phase III) in October 2007. This phase is planned for a duration of ten U.S. federal fiscal years (October 2007 to September 2017), and its main focus is the characterization and monitoring of large-scale CO2 injection into geologic formations at CCUS sites. The Plains CO2 Reduction (PCOR) Partnership, led by the Energy & Environmental Research Center (EERC), is one of seven regional partnerships established under the RCSP Program. The PCOR Partnership region includes all or part of nine U.S. states and four Canadian provinces (Figure 1) and is made up of numerous private and public sector groups (Figure 2) working to identify the most suitable CO2 storage strategies and technologies, aid in regulatory development, educate the general public, and investigate appropriate infrastructure for CCUS commercialization within its region. The Phase III program undertaken by the PCOR Partnership includes two commercial-scale projects that are of immediate interest to the oil and gas industry, namely the Fort Nelson carbon capture and storage (CCS) feasibility project and the Bell Creek combined CO2 EOR and storage project.
Extending Mature Well Life by Innovative Slurry Design and Complex Coiled Tubing Wellwork
Authors: A Razak M Hairi , Azman Aulfah , Timan Haryati , Kasim M Heikal , Ishak M Fakhrurazi 
Published: May 2016

Abstract
Well integrity possesses major challenges for field operators all over the world. A packer leak is common amongst many other well integrity issues especially for old well. One well in South China Sea was diagnosed with ultrasonic and temperature logging and proved to have such problem forcing the field operator's to shut in the well due to safety concern as the leak create high tubing annulus pressure. Total production lost was 500 bbl of oil per day. Through tubing wellwork was chosen as preferred option because it is more economical relative to workover particularly for such well in a mature field where reserve was depleted. A multiple through tubing wellwork operations using calcium carbonate and cement design with different strategies and methods had been attempted but results are temporary cure at best. Determine to success, previous work program was thoroughly examined inclusive the slurry recipes. The intervention methods were reviewed and challenged, then later refined. Finally, enhanced and optimized cement slurry is engineered together with different approach of well work in which specifying the requirement for acoustic fluid level monitoring. The packer leak was successfully repaired. This paper will discuss the previous coiled tubing method or approach that was failed, the reasons behind the failure and current work program that prove as successful. The innovative slurry design and best practices will also be deliberated.

Introduction
An oil and gas producing field is located at 260km from Kerteh, Terengganu. It was first explored in the block in 1971, which then produced its first oil in 1978. The field is located at southeastern part of the Malay basin with average water depth of 70m.
The field consists of both gas and oil reservoirs. Currently, the field has two mother platform and 1 satellite drilling platforms which locate all the surface facilities such as oil and gas processing, produced water system, water injection facilities and other utilities system. The produced oil and gas then being transported to the shore via a common crude oil pump platform for oil and to a common gas processing platform (CPP) for gas.
Production Technology Challenges of Tight and Shale Gas Production in China
Authors: Lau Hon Chung , Yu Meng 
Published: May 2016

Abstract
Natural gas production from tight and shale gas reservoirs is becoming increasingly important in China as the country shifts from coal-based energy to cleaner energy sources. Recent Chinese sources have estimated that the gas-in-place resources from tight and shale gas reservoirs in China are at least 12 and 31 Tcm, respectively1. In 2008, annual production from tight gas reached 20 Bcm, about 23% of natural gas production in China1. Commercial production from shale gas reservoirs is yet to begin, but is expected to grow rapidly in the future.
This paper gives an overview of the production technology challenges of tight and shale gas production in China. Based on a review of the published literature and their own observations, the authors have identified a number of key production technologies that are relevant and can potentially make significant impact on tight and shale gas production in China. They include, among others, management of H2S risks, sourcing and disposal of water for hydraulic fracturing, pad drilling and completion, incorporation of geomechanics in well design and reservoir modeling, non-formation damaging fracturing fluids, and improved multi-stage fracturing techniques. This paper should be of particular interest to subsurface engineers, scientists and managers who are involved in tight and shale gas production in China. It will also be of interest to researchers in universities and research institutes who are interested to develop these technologies to unlock unconventional gas resources in China.

Introduction
Currently, China is the world's largest energy consumer and second largest oil consumer2. In 2011, 70.4% of China's energy consumption came from coal, 17.7% from oil and only 4.5% came from natural gas3. Emission from coal-burning power plants and automobiles are the two major sources of air pollution in China. Consequently, the key for China to move to a low-carbon economy is to reduce the use of coal and increase the use of natural gas. National consumption of natural gas in China in 2011 was 130.7 Bcm, a 21.5% increase from the previous year (Fig. 1). In the same year, national production of natural gas was only 102.5 Bcm. The gap of 28.2 Bcm, or 22% of national consumption, was satisfied by import by pipeline from Central Asia and from liquefied natural gas from Middle East, Africa, Australia and Southeast Asia3. In the last three years, the national consumption for natural gas has far exceeded domestic production. In order for this gap to be bridged, domestic production of natural gas, especially from unconventional resources such as coalbed methane (CBM), tight and shale gas reservoirs must be increased drastically. This need to grow domestic output of unconventional gas production has been recognized both by the government and private sector, thus giving tremendous impetus to the development of tight and especially shale gas reservoirs.
Research and Practice of Daqing Oilfield on Fine and Efficient Water Flooding Development at the Ultra High Water Cut Stage
Authors: Pang Yanming , Du Qinglong , Jiang Xueyan , Guo Junhui , Zhu Lihong , Zhang Shujuan , You Chunmei 
Published: May 2016

Abstract
Being developed with water flooding for more than 5 decades, the Daqing Oilfield is now in a developing period of ultra -high water cut. But the remaining oil still exists, and is in a status of highly scattered. As to the recognition and exploration of the remaining oil, the high-efficiency development strategy is promoted in this paper. The mechanism of improving development effect by fine waterflood adjustment is firstly studied by the using of numerical and physical methods, the practice and result of water flooding fine potential tapping are systematically discussed. Field application at the 6 pilots shows satisfactory performance for 3 years under the water cut of 92%. This offers a new way for the fine and efficient water flooding development of maturing oilfields at the ultrahigh water cut stage and valuable reference for water flooding development of multilayered sandstone oilfields.

Introduction
Daqing Placantieline Oilfield has entered into the "ultra-high water-cut and ultra-high recovery factor" development phase, with the recovery percent of recoverable reserves of 86.49% and the water cut of 92.75%. Waterflood development of Placantieline oilfield has faced many development problems, such as high water cut of all wells and layers and scattered distribution of remaining oil. The waterflood adjustment efficiency by macroscopic well pattern structures has become lower. The difficulty to control water cut and production decline by waterflood development has been becoming larger. Therefore, the current waterflood adjustment technology can not completely satisfy the need for fine waterflood adjustment at ultra-high water cut period[1,2]. In 2010, Daqing Oilfield launched 6 pilots for fine waterflood remaining oil tapping at ultra-high water cut period, lots of waterflooding technologies have been applied thoroughly. Meanwhile, by the application of fine reservoir description, fine injection-production system adjustment, fine injection-production management, each item of work involved in oilfield development and management has become more meticulous. Through all these efforts, production decline and water-cut increase have been prevented successfully for three years in these pilots.
A Coil Shooting Survey in the Angola Deep Offshore
Authors: Zamboni E. , Khaled N. , Kusuma A. , Guerra J. , Capelle P. , Tchikanha S. , Larragana D. 
Published: May 2016

Abstract
The Calulu PDA (Pre-Development Area) is located in the Angolan deep offshore. The water depth ranges from 1500m to 2500m. The area is characterized by a very complex geological settings caused by the presence of extended salt canopies. The main reservoir levels are turbiditic sands located in highly structured sub-salt areas. The area was covered in 1999 by a conventional Narrow Azimuth Towed Streamers (NATS) 3D seismic survey. As most acquisitions of that period, the data suffer of an intrinsic limitation: the maximum recorded offset is about 3.5 km. Despite recent reprocessing efforts with the latest state of the art techniques (3D SRME and RTM) the final data quality was still not sufficient to correctly image the complex salt tectonics structures and the steeply dipping anticlinal flanks. For this reasons, in 2011, TEPA and Partners decided to acquire a long offset (more than 7 km) NATS seismic survey over the area (~1300 Sq. km) complemented by a coil shooting survey over a sub-area of interest (~700 Sq. km). The required turnaround deadlines for the whole project (Fast Track and Final Processing) was a real challenge for all the parties involved (TOTAL and WesternGeco): a raw TTI (tilted transverse isotropic) RTM PSDM was available within 4 and 5 months respectively after the last shot point for the NATS and Coil. As a seamless workflow, the full processing took then the pace to deliver the final results within 12 months after the last SP. Scope of the final processing was to refine the existing TTI velocity model and produce improved images, with respect to the Fast Track, of the Coil data set using various migration algorithms (Beam, Kirchhoff and RTM). The most representative results among the different techniques from both surveys are presented and compared in this paper.

Acquisition overview
The coil shooting technique allows the acquisition full azimuth (FAZ) seismic data. It consists of a single vessel navigating in circular path and recording data over the full range of offsets and azimuths. This technique has the potential of improving seismic imaging in subsalt provinces. In our specific case the coil shooting survey was designed and implemented in order to deliver high fold and a full azimuth distribution over an area of interest (Khaled & al, EAGE 2012).
What Matters to Flow: West Africa Field Case History
Authors: Thomson Brodie , Apanel Anna , Tester Robert , Marques Gaspar , Mateus Ginga 
Published: May 2016

Abstract
The subject field, located in deep-water Angola Block 15, was discovered in 1999, achieved first production in 2003 and was abandoned in 2011. Over its 7-year life, the field reached a peak production of 90 thousand BOPD and produced nearly 100 million barrels of oil from a high-quality stacked Lower Miocene deep-water channel complex. This field provides a unique opportunity to perform a look back on how well the reservoir characterization, reservoir modeling and reservoir performance predictions made at project funding matched with the final actual field performance.
The West Africa field was a subsea development tied back to a FPSO (Floating Production Storage Offtake vessel). The original depletion plan called for crestal gas storage and peripheral water flood. The field was ultimately developed with a combination water flood / downdip gas injection process. The factors that drove the evolution in the depletion plan are reviewed.
Despite the significant changes to the depletion plan, the funding models did a good job of predicting average reservoir behavior such as most-likely recovery and production plateau. However, both gas and water breakthrough and build up was faster than expected. These factors were offset by higher well productivity and larger in place oil volumes. The reasons for the models not matching actual performance are discussed. 4D seismic acquired after 3 years of production was particularly effective in illuminating gas and water flow pathways in the reservoir that had not been modeled or predicted.
Water injection was not initiated until about three months after first production. Initial field performance under pressure depletion drive provided valuable reservoir characterization data. Early pressure decline was slower than predicted; material balance indicated that a higher STOOIP was needed as stronger aquifer support alone was not sufficient to match observed pressures. Late field life data showed a more complex situation, indicating an even stronger aquifer than had been previously modeled. The impact of aquifer strength on pressure support was not fully recognized at project funding time.
For most subsea developments with limited ability for well intervention, reservoir surveillance data from permanent down-hole pressure gauges and particularly 4D seismic are critical to effective reservoir management. Learnings from this field have been applied to other West African deep-water developments.
Forming Mechanism and Petroleum Geological Features of the Western-Central African Rift Basins (WCARBs)
Authors: Pan Xiao-Hua , Yuan Sheng-Qiang , Ji Zhi-Feng , Hu Guang-Cheng , Liu Li 
Published: May 2016

Abstract
With the exploration activities of China National Petroleum Corporation (CNPC) in Sudan, Chad and Niger, more and more 2D, 3D seismic data had been required, a series of exploration and appraisal wells had been drilled, and more of other geologic materials had been obtained, such as well logs, core, geothermal gradient data, geochemistry data etc. Based on these abundant data and integrated application of geophysics method, physical modeling, computer modeling and geological analysis etc., the authors carried out an in-depth study on the Western-Central African Rift Basins (WCARBs), coming up with an understanding that the Basins are of passive rifts different from the so-called active ones formed in result of mantle up-welling. The WCARBs present unique petroleum characteristics including low geothermal gradient, aggregate thin-bedded hydrocarbon source rocks in syn-rift sequence, small-scaled post-rift sequence and high-angle basin-controlling major faults etc., and as a result, exhibit petroleum systems with unique characteristics, such as late and long-lasting oil generating window, high oil-expulsion efficiency, and fault-block dominated traps with rare rollovers etc. The deep study and analysis of the basin structure, sedimentary features and petroleum system obviously enhance the exploration discovery of WCARBs, which is the key factor of the successful E&P activities of CNPC in WCARBs.
Depositional and Diagenetic Sedimentological Model of Najmah-Sargelu Formation, Umm Gudair, Kuwait
Authors: Ray D. Singha , Al-Shammeli A. , Al-Khamees W. , Fuchs M. , de Groen V. 
Published: May 2016

Abstract
Najmah-Sargelu Formation of Middle Jurassic is tight, fractured Carbonate reservoirs, spread across many fields in Kuwait. These reservoirs are often vertically and laterally heterogeneous because of depositional variability and diagenetic alteration through space and time. Understanding the distribution of hydrocarbons in relation with porosity / permeability heterogeneities is thus of major importance in effective field development and production. A proper sedimentological model is then a mandatory step in matrix characterization to make an accurate numerical reservoir model, predicting fluid flows through time in order to support development scenarios.
This paper presents an overview of efforts in building a sedimentological model based on the analyses performed on cores penetrating the Najmah and Sargelu Formations of the Umm Gudair field. The data obtained from the description of cores allowed defining a sedimentary facies scheme that served a basis for building of a 3D sedimentological model. Dominant sedimentary structures and bioturbation traces have been taken into account for the facies classification. The apparent differences in texture between the core-based lithotype scheme and the thin-section based microfacies scheme is due to intense micritization of grains.
This model shows a moderate-energy carbonate ramp with a relatively flat morphology, further subdivided into three major depositional environments: The mid ramp, outer ramp, and basin. The basin includes: evaporitic conditions, restricted/anoxic conditions, unrestricted/oxygenated conditions. The basinal deposits are mostly characterized by shaly mudstones that host the deposition of a calciturbidite sheet complex. The mid- and outer-ramp settings are mostly dominated by relatively fine sedimentary textures where the structures are obliterated by intense bioturbation.

Introduction and objectives
Najmah-Sargelu Formation of Umm Gudair is often vertically and laterally heterogeneous because of the combination of several factors such as depositional variability or diagenetic alteration through space and time. This heterogeneity should be taken into account during a field development; otherwise substantial amounts of potentially producible hydrocarbon will be bypassed during production. Understanding the distribution of oil and gas in relation to porosity / permeability heterogeneities is thus of major importance in effective field development and production. A proper geological characterization and modelling is then a mandatory step in building an accurate numerical reservoir model that will be able to reproduce and predict fluid flows through time in order to support development scenarios.
Advances in Technology of CBM Horizontal Well Completion in Deep Area
Authors: Yuan Zhengrong , Kleverlaan Martijn , Dong Jinpo 
Published: May 2016

Abstract
In 2011, a deepest horizontal Coalbed Methane (CBM) well in China, with a total vertical depth in excess of 1100m, was successfully drilled by Shell China E&P Co. Ltd (SCEPCo). The well, located in the East Ordos Basin, achieved a total 'in-seam' length of nearly 3600 m. The integration of technology across multiple disciplines, which enabled this well to be a success, is presented in this paper. An integrated geological evaluation of both regional and block scale data was used to map the depth, continuity, thickness and gas content of the coal seams. This evaluation, together with understanding of structure and distribution of faults, was then used to pick a well location in an area where the coal seams are thick and the gas content is high. The uncertainties in the evaluation are greater where the coal seam is deeper and include factors such as the stress field, coal mechanical properties, structural complexity of the seam, presence of a roof aquifer and the permeability. When planning the drilling of the well, a comprehensive drilling strategy, together with sidetrack and drilling fluid programs were prepared prior to the campaign. This preparation was invaluable for successfully drilling the first horizontal well despite the geological uncertainties present. The MWD technology and expertise in geosteering were also essential to successfully drill the horizontal laterals in this area as there is a potential aquifer in the limestone roof which needs to be avoided and there are kink bands in the coal seams. A geomechanical evaluation was also completed to understand the stress field and the orientation of fractures in the coal seam. This is required to understand and balance the trade-off between orienting the horizontal laterals to maximize production against maintaining the stability of the well bore. After completion of the well, the well production was initially affected by several shut-ins which delayed gas production. A combined dewatering and control system was then adopted which was shown to effectively mitigate fluid level buildup issues arising from unexpected workovers and well shut-ins. In conclusion, this well demonstrated the feasibility of drilling horizontal CBM wells in the area deeper than 1100 m and it is expected that this technology can be applied in the near future to unlock the potential of other deep CBM opportunities in China.
Modelling Seismic Responses in Heterogeneous Gas Reservoirs: A Theoretical Approach of Rock Physics
Authors: Ba Jing , Chen Zhiyong , Cao Hong , Yao Fengchang , Xu Guangcheng , Zhang Xingyang , Li Jinsong , Lu Minghui 
Published: May 2016

Abstract
In actual gas reservoirs, generally natural gas is heterogeneously distributed in the host matrix of water-saturated rocks, forming countless small "patchy" -like gas packets. This heterogeneity feature (also called the "patchy-saturation") will cause the elastic wave dispersion and attenuation in a seismic exploration band (101~103Hz). The reveal of the relations between seismic responses and reservoir fluid distributions will significantly improve the precision of reservoir characterization and fluid identification in exploration engineering. This paper uses a double-porosity model to describe the gas/water patchy-saturated rocks. On the basis of Biot-Rayleigh (B-R) equations, multi-scale rock physics modeling is performed aiming at gas reservoirs. The wave responses in seismic, sonic (103~104Hz) and ultrasonic (&gt;104Hz) bands are predicted and then quantitatively related to the basic properties of lithology and fluids. This approach of modeling is applied in limestone gas reservoirs located on the right bank of Amu Darya river. A multi-scale rock physics template is presented based on the theoretical studies. By combination with the method of the pre-stack inversion of reservoirs' elastic constants, two key parameters of gas saturation and porosity are finally estimated.