bluuebunny/crossref_metadata_2025 huggingface dataset:
An Integrated Approach to Phase-Wise Marginal Fields Cluster Development - A Case Study of C Series Offshore Fields, India
Authors: Vasudeva Sudhir , Nischal Rajiv , Kumar Adesh
Published: May 2016

The C-Series fields are mainly gas bearing with marginal reserves distributed in multiple pays and spread over a large area. They are located in the Arabian Sea, far away from existing infrastructure, in shallow water depth (24–30m), having very high under currents and adverse weather conditions. As independent development was not viable, concerted efforts involving integration of human resources, advanced technologies improving scale of economies by cluster development and changed economic scenario, these fields could be made economically feasible.

The paper brings out how development has been undertaken using new concept and technologies in a phased manner to reduce capital cost of platforms, pipeline & processing facilities to maintain plateau rate for a few years. This paper discusses multidisciplinary task based parallel working with real time integration of results and midcourse corrections while formulating fast track phased development plan. The functional tasks included geological modeling, reservoir simulation, innovative well drilling and well design, assessment and adequacy of existing and nearby facilities and pipelines to minimize offshore development cost, simulation of fluid flow dynamics for both wells and pipelines for various operating conditions, well design & drilling options, well completion, selection of material, equipments and facilities. Besides setbacks in some fields, substantial upward revision of gas in place has been established in other area and it has been decided to advance the later phase development for early monetization of upside reserve using an old rig to be converted as MOPU for phase segregation and compression. This paper also discusses brief details of the selected options while presenting this classic case of this challenging offshore cluster development.

Introduction

Many small & marginal fields have been discovered in western offshore, India and C-Series is one of them. The C-Series small & marginal fields comprises of fields, namely C-22, C-23, C-24, C-26, C-39-1/3, C-39-6/8, and B-12 Structures. These fields [1] lie in a NE- SW alignment spread over a distance of 110 Km, situated in Tapti Daman block of Mumbai Offshore Basin. They are in Tapti-Daman area of western offshore in Arabian Sea at about 160 to 200 Km from the city of Mumbai and about 60 Km west of city of Daman. These are mainly gas bearing with reserves distributed in multiple pays and spread over a large area. The farthest field is located about 180 Km away from existing Mumbai High North Platform (NQ). These fields lie in a roughly NE-SW alignment, spread over a distance of 110 Km, and are mainly gas bearing in Daman and Mahuva formations. These fields are in shallow water depth (24–30m) having very high under currents and adverse weather conditions.
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

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

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

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

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

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

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

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

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

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

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 (>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.
Recent Advanced Applications of Formation Testing in Daqing Oil Field Aiding Field Development
Authors: Wu SX. , Chen ZF. , Chen J. , Xian C.
Published: May 2016

Extended Abstract

This paper is to summarize the advanced applications of formation testing in Daqing field in recent years and to share the experience on how to use formation testing technology to improve field development plan adjustment by understanding better the water movement and EOR fluid front distribution using formation testing technology.

Daqing Oil field is the most critical oil field in China to supply stable oil production for Chinese domestic demands. It involves continue exploring of new reserve in more and more challenging formation and continue pushing for higher oil recovery by fine turn water injection strategy and utilizing leading edge EOR technology. In order to achieve this objective, the latest formation testing technology has always been evaluated and applied in Daqing development field in last 10 years. Tons of pressure and fluid data has been collected to in such an efficient and cost-effective approach.

Other than fluid typing and obtaining fluid samples in exploration wells, the conventional formation testing applications, formation testing has been used more in development field in Daqing field recently to understand water movement helping defining infill drilling plan and in EOR stage, to understand EOR fluid front. This helps the field operator greatly to figure out the potential of a mature field and maintain stable production ultimately.
Measuring and Profiling Casing Corrosion for Predicting Subsurface Leaks
Authors: Al-Yateem K.S. , Kohring J.J. , Qahtani H.B. , Garcia J.
Published: May 2016

Locating downhole casing leaks in producer and injector wells is not a complex undertaking when using rig-operated straddle packers with pressure testing. However, this established technique has limited effectiveness because it does not necessarily address the overall comprehensive integrity of the entire completion, which might include additional intervals of serious corrosion leading to leaks in the near future.

We examined the results of low-frequency electromagnetic (EM) remote frequency eddy current (RFEC) wireline logs from over 80 wells in one mature Middle Eastern offshore field, profiling the severity of measured metal loss (ML) from concentric casings against proven rig-discovered leaks and rigless measurements of subsurface ML. Casing leaks that otherwise would have been detected only by conventional zonal pressure testing from a workover rig can now be located and forecasted with a high degree of probability when using this evaluation tool.

The importance of maintaining oilfield casing integrity for safety, environmental, and flow assurance objectives, combined with the high costs of drilling new wells, creates a necessity for this integrated well integrity appraisal approach. Application of this EM logging technology to identify intervals of external ML has great significance in being able to anticipate casing intervals with high likelihood of failure due to invasive corrosion.
Application of Nozzle-Based Inflow Control Devices (ICD) in AL- Khafji Field
Authors: Abd Elfattah Mahmoud , Gottumukkala Varma , Sadah Ahmed Alawi Ahmed , Mohamed Tawakol I. , Nufaili Subhi Ali
Published: May 2016

Al-Khafji field, located in the Arabian Gulf, contains an unconsolidated sand reservoir subdivided into two reservoirs (A and B). The main obstacle in Al-Khafji field is water encroachment due to unfavorably high-water mobility compared to oil; therefore, the field presents a reservoir management challenge in the form of curbing water production in these relatively high-permeability sandstone reservoirs. Both reservoirs (A and B) have irregular water-front movement and water encroachment is dominated by edge-water drive for reservoir A and bottom water drive for reservoir B. Water coning/fingering problems are evident even in the crestal regions. This water encroachment problem can be explained by one or combination of:Water movement behind casingWater movement along conductive fault planes

Typical Al-Khafji field horizontal wells are completed with cemented liners and perforations. The wells typically water out during the initial production phase because of the reasons explained previously and limitations on surface water handling capabilities adds to the problem by preventing the wells from flowing at their full potential.

A new technology for horizontal well completions has been proposed by integrating 350-µm screens with inflow control devices (ICD) and packers to curb the water production by delaying water breakthrough and managing sand production. Numerous wells in the field have been completed with a nozzle-based ICD, and the promising results will be discussed during the course of the paper.

The ICD-completed wells will be analyzed and compared with nonICD-offset wells. The parameters that were used during the ICD-completion design to overcome the main field challenges will be highlighted. Completion strategy has been changed in Al-Khafji field based on positive performance results from the ICD-completed wells.
Enhancing Drilling Safety Performance Through Effective Communication Culture
Authors: Boucif Mustapha Nasreddine , Al Mutawa Ahmed
Published: May 2016

There is no way to obtain zero injuries in any organization without the commitment of the workforce. This article will show how Abu Dhabi Company for Onshore Oil Operations (ADCO) Drilling Division and its contractors obtained employee commitment resulting in world class performance in HSE for the past five years and recorded the lowest Total Recordable Injury Rate (TRIR), the second lowest Lost Time Injury Frequency (LTIF) in ADCO's Drilling Division history and the longest time without LTI (Eighteen months without LTI) in 2011. In addition we have recorded zero car related injuries for the past four years and zero spills in 2011.

DOIRC (Drilling Operations Incident Review Committee), a monthly meeting with all our contractors was a key factor in improving the safety performance of the drilling community by developing 360° communication between ADCO main office, ADCO field, Contractor's management office and their teams in the field. The forum also have shifted from a reactive committee where only incidents are discussed to a proactive forum where best practices are shared and a communication network was established to inform the fields on regular basis.

In addition to that, High Profile Tours (rig visits by ADCO Top Management), DOIRC High Profile Tours (rig visits by ADCO and contractors Top Management), onsite workshops and regularly launching campaigns with our drilling contractor National Drilling Company (NDC) were the additional tools used to raise Drilling Division performance to a world class performance.

ADCO Drilling Division has clearly established a successful formula for its safety performance to reach and maintain a world class performance for the past four years, reaching 0.52 TRIR in 2011 and 0.09 LTIF in 2008 and 2010;the lowest in ADCO Drilling history through effective communication culture.
Production Forecasting and Analysis for Unconventional Resources
Authors: Zhou Wentao , Gupta Siddhartha , Banerjee Raj , Poe Bobby , Spath Jeff , Thambynayagam Michael
Published: May 2016

Horizontal well drilling with multistage fracturing technology has been the common practice to develop unconventional resources. During the development of such resources, we are often faced with the following questions: How can we optimize the stimulation treatment? How much can the well produce? What are the production data telling us? Answering these questions requires technologies and tools to be able to forecast and analyze the production behavior of fractured wells.

We investigate the physics and mathematics involved in production forecasts of both planar fractures and fracture networks that are generated due to stress isotropy and pre-existing natural fractures. We use analytical methods because they give rigorous yet very fast solutions. Since simulation expertise is not required to use our model, it is an accessible tool for multiple disciplines. A new nodal analysis approach is proposed for unconventional resources.

Production forecasting enables the optimization of a well stimulation treatment, and helps to determine, for example, the number of fracture stages and the amount of proppant to use. Case studies illustrate the concept and some of the practical aspects of fractured well production, such as the impact of propped conductivity and unpropped conductivity.

The composite workflow for diagnosis and analysis of production data specific to unconventional resources was applied to real case examples. The workflow involves flow regime identification, decline curve analysis, and rate transient analysis. The workflow is easily scaled from single-well level to well clusters to full field implementation.
Construction and Operation of HPHT Pipelines Designed for Lateral Buckling in the South China Sea
Authors: Ramaiah N. , Bong A.
Published: May 2016

Gas production in the South China Sea has seen increasing trend of pipelines operating in HPHT (high pressure and high temperature) condition. This has led operators to stretch beyond the conventional stress-based design and move into strain-based design using the lateral buckling design approach. In previous article by Nils Kristiansen et al [1] and paper by Lim Kok Kien et al [2], the lateral buckling design methodology and initiation method were discussed and verified against field data. This paper presents both construction challenges and operational works following post start-up. Construction cost benefits for proven initiation method and actual laboratory data resulting from material testing for the purpose of welding acceptance criteria are included in this discussion. Routine maintenance practices, engineering post start-up and operating envelope developed for pipeline designed for lateral buckling will also be discussed. The intent is to provide operators with cost effective construction solutions and risk-based maintenance philosophy when considering lateral buckling design.

Introduction

Increasing temperature and pressure in gas production has led some operators to stretch beyond the conventional stress-based design for pipelines. One of the methodologies to address HPHT condition is the state-of-the-art lateral buckling design. Lateral buckling design is a strain-based design that allows the pipeline to expand laterally at designated locations in a controlled manner. This allows the pipeline to relieve its thermal expansion by lateral movement rather than being axially restrained (i.e through trenching and burial).

As with any non-conventional methodology, such design has certain limit states which require careful consideration. The limit states are local buckling, low cycle fatigue, fracture and pipeline walking. These limit states are addressed during the design phase except for fracture; which is addressed during construction phase. During operation, these limit states are also monitored periodically to ensure that the design thresholds are not exceeded.
A New Calculation Method for Single Well Controlled Dynamic Reserves of Tight Gas
Authors: Zhenhua Cai , Xinwei Liao
Published: May 2016

Tight gas features with low permeability and process of flow is complex. Gas well production is based on dynamic reserves. The traditional methods include volumetric method and material balance formula which uses the shut-in pressure measurement data to calculate the dynamic reserves. This paper raises a new method to calculate dynamic reserves with BHP. The advantage is with no need for shutting well and compared to well-test, the result is accurate.

Introduction

The tight san gas is one type of unconventional, has ultra-low permeability. If without enhance treatment, can't get industrial flow. So enhance treatment is necessary. The boundary of tight gas is dynamic therefore well controlled reserve is dynamic as well. Conventional method for reserve calculation of gas reservoir include Volumetric method, material balance etc. Volumetric method is applied of static reserve and material balance need formation average pressure which is difficult to measure. For poor connectivity, it takes couple month even year for well shut to gauge formation pressure Pr. Shutting well for long time cause huge lost for production unit. The method presented in this paper gains dynamic reserve without gauge Pr, and approved by real example.
Characterizing Fluid Distribution in Highly Compartmental Chinese Oilfield by Advanced Cased-Hole Formation Testing
Authors: Ma J. , Yu H. , Wang Y. , Xian C. , Yang L. , Fu L. , Chen J.
Published: May 2016

Yingdong oilfield in West China is one of the biggest discoveries recently in china land with probable reserve estimated to be over 100 million tons oil equivalent. This field is small in area coving around 8.1 km2 only. But the oil column is over 400 meters in one of the exploration well and distributed in more than 100 sand zones. Recent seismic work reveals that this reservoir is extremely complex on structure due to the faulty nature. As the consequence of this, significant reservoir compartmentalization is expected and proved by newly drilled appraisal wells. Two wells with only a few hundred meters distance demonstrate completely different hydrocarbon water system. Thus understanding the type of fluid and its distribution becomes the biggest challenge for Yingdong field appraisal and planning the field development in the near future. And testing all these thin zones becomes impractical considering the cost and the time constrains.

A recent project of using Cased-Hole Formation Tester to characterize the fluid type and distribution in three wells in this field was accomplished with great success. 20 zones were carefully selected in three critical wells and tested within one-month time. Besides obtaining high quality fluid samples, the hydrocarbon properties, (GOR, composition, bubble/dew point, etc) are also evaluated in real time with the latest downhole fluid analysis technology. It provides timely input to the current production pilot work. The log interpretation results have been revised in quite a few zones with this formation testing answers also.
The Indicator Diagram Collection Based on the Beam Pumping Unit Motor Effective Power Measurement
Authors: Guo Yueming , Ma Liang
Published: May 2016

Conventional beam pumping unit is the most popular lifting equipment at well site, especially in mechanical oil production. To identify its operation, the indicator diagram is an effective tool. Therefore, study on indicator diagram measuring methods has been made as a key subject in major oilfields in China. Currently, force sensors and displacement sensors are commonly used to measure the polished rod load and displacement, so as to generate the indicator diagram. The force sensor is always exposed to the compression and tension of alternating loads, which will damage its elastic coefficient, finally leading to less-precision or even invalid measurements. Besides, this application may bring challenges in installation of devices, work life of the sensors, maintenance and operating cost, which will affect the analysis of well conditions. In summary, the technique cannot satisfy the current requirement of digitalized well management.

In view of above issues, this paper proposes a new measurement method. The useful motor power of the beam pumping unit is acquired in real-time manner, and based upon the law of conservation of energy, the motion pattern of the unit is analyzed, to establish a mathematical model containing useful motor power, polished rod load and polished rod displacement. The model can figure out the relationship between beam pumping unit output power and load. Then, in line with field physical calibration, the indicator diagram is measured. This method doesn't require complex installations on the site. Instead, only electric parameters for input and useful power, apparent power and power factor are acquired to determine the actual polished rod load, according to the correlation between power of the unit and load. Finally, the indicator diagram of the pumping unit is measured indirectly. This method can greatly contribute to the site installation efficiency, work lift of measuring devices and measurement accuracy.

This method has been tested in 20 pumping wells. It is found that the equivalent indicator diagram illustrates accordant tendency with the measured indicator diagram; average relative error of area is less than 8%, and average relative errors of maximum and minimum loads after calibration are not greater than 10%. These suggest that the equivalent indicator diagram reconcile with the measured one, and can be used in real time monitoring of pumping well conditions by using useful motor power data. This technology has been effectively applied in an oilfield domestically.
The Awakened Giants
Authors: Abdullah Che Shaari B , Mohamad Khazali Nur Fadzlinda Bt
Published: May 2016

Introduction

Since late 1960's, there are intensive exploration activities conducted off the coast of the state of Sarawak, Malaysia. The offshore region to the northwest of Borneo Island saw a heightened state of exploration activities for hydrocarbon following increasing demand for fossil fuel as a result of world industrialization. Miocene carbonate pinnacles are one of the target play types identified and chased within the Central Luconia geologic region. In those days the more obvious, mega size shallow carbonate build-ups which are considered as the "low laying fruits" became the first priority exploration test candidates. Some of the pinnacle build-ups are proven gas fields with few of them classified as "giant class" accumulations (Figure 1). Nevertheless, a lower than expected overall exploration success statistical trend coupled with low priority in the business strategy for gaseous hydrocarbon further compounded the issues which arrested the exploration initiatives. A "hiatus" in exploration activities ensued beginning in 1980's. On the subsurface side, geologic assessments then identified hydraulic seal failure and "thief sand" as the probable contributing factors in the unsuccessful cases. Extremely high aquifer pressure combined with the hydrocarbon buoyancy effects thought to have breached the cap seal mechanical strength which caused capillary hydrocarbon leakages. The presence of post carbonate permeable sandy formation down lapping onto the pinnacle is the other identified geologic risk element. Inter-fingering of the sand and carbonate introduced leak point which provided drainage conduit diverting the hydrocarbon away. The incriminating "blown trap" theory was thence adopted loosely as an explanation to the situation. On the other hand apparent deeply buried pinnacles are intuitively associated with high formation pressure, temperature and non-hydrocarbon gas contaminants further added up the situation complexity. The anticipated drilling operation complications from such conditions are henceforth associated with potential high costs. These conditions summed up have led to premature condemnation of the remaining carbonate pinnacle play type potential in the region. There was absolutely no interest to further realize the hydrocarbon potential of the pinnacles since then.

Recent works within the region re-evaluating the similar pinnacles have proved the contrary. The pre-conceived misconceptions of the play types were rectified and adoption of the findings proved very rewarding conclusions.
Materials and Corrosion in LNG Industry - Our Experiences
Authors: Murty J. V. D. , Muzghi Ibrahim A.
Published: May 2016

1.ABSTRACT

Liquefied Natural Gas (LNG) industry utilizes a variety of materials to serve its needs in diverse service conditions, from cryogenic to moderately high temp applications, to a multiplicity of corrosive environments. The content of the submission is applicable all across the LNG industry.

This paper focuses on the applications and materials used by Qatargas for LNG production, at both onshore and offshore facilities. It examines mechanical and metallurgical concerns with emphasis on areas of corrosion and the solutions devised to address these items of interest. The presentation discusses in detail case studies and Qatargas experience in selection of materials, metallurgical problems faced and their failure mechanisms such as graphitization, sigma phase formation etc.; mechanical in nature such as vibration induced fatigue etc.; corrosion in nature such as crevice corrosion, environmental assisted cracking, flow accelerated corrosion, aggressive environmental corrosion etc. and solutions arrived for each of the cases.

These case studies will be supported by data, analysis, with photographs and other relevant facts and figures for reference as well as details of solutions and remedial measures implemented for each of the cases.

As subject matter of the presentation presents case studies of problems faced and solutions reached, the information will be directly applicable to similar service conditions and will be of direct significance to LNG industry.

2.INTRODUCTION LNG INDUSTRY

The share of Natural gas in the basket of different types of raw energy produced around the world is growing. No doubt, Natural gas from conventional gas reservoirs is the major source of supply, though shale gas, coal-bed methane etc. are proving to be promising developments. Meanwhile, the growing need for cleaner power production is driving major fast growing economies such as China, India and South Americas to invest in more natural gas-burning power plants. The low price of gas as a result of a gas glut in the US is making gas a more competitive source of power than oil and renewable energy technologies such as wind and solar power.