bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Application of Innovative Fiber-Diverting Technology Achieved Effective Diversion in Acid Stimulation Treatments in Saudi Arabian Deep Gas Producers
Authors: Solares J. Ricardo , Al-Harbi Moataz , Al-Sagr Abdulaziz , Amorocho Ricardo , Ramanathan Venkateshwaran 
Published: October 2008

Abstract
Acid fracturing has been an integral part of Aramco's gas development strategy for the vertical wells in the Khuff carbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acid fracturing. During acid fracturing, the wormholes created by the reaction, results in excessive fluid loss. Controlling fluid loss is key to optimize acid fracturing treatments by creating longer and wider fractures. Diesel emulsified acid for deeper penetration and in-situ gelled acid, a polymer-based system, are used to control excessive leak-off at different stages of the treatment along with the alternating stages of polymer pad.
These treatments in the vertical wells target several reservoir sub-layers with varying degrees of porosity and permeability contrast. These layers are often divided by anhydrite or dolomitic streaks that make vertical communication within the reservoir challenging. Hence acid fracturing ends up stimulating the highest reservoir quality zones with minimal contribution from the other zones in many cases.
A pilot involving the use of a new degradable fiber technology designed to achieve effective acid diversion during acid fracturing was recently implemented. The pilot comprised field trials in a number of wells with similar reservoir characteristics and multiple porosity lobes. The fracturing treatments were designed and pumped with alternating stages of acid and fiber-laden polymer based pad fluid. The significant viscosity increase achieved in the pad by the addition of fibers and its particulate bridging mechanism would plug off the just stimulated zones effectively, thus diverting the new stage of acid into the non-stimulated porous zones. These fibers degrade and hydrolyze with temperature and time thus leaving the reservoir undamaged.
This paper discusses the planning and design processes leading to the successful implementation of the technology, the experience during the stimulation treatment execution and the excellent post-stimulation results. Bottomhole pressure gauge data and production logs were run on these wells to ascertain the effectiveness of the technology and the results are discussed in the paper along with production history comparisons with offset conventionally acid fractured wells, and the lessons learned throughout the pilot.
Water-Flooding Incremental Oil Recovery Study in Middle Miocene to Paleocene Reservoirs, Deep-Water Gulf of Mexico
Authors: Liu Bin , Dessenberger Richard , McMillen Kenneth , Lach Joseph , Kelkar Mohan 
Published: October 2008

Abstract
Many deep-water Gulf of Mexico discoveries of the past five years are older Tertiary reservoirs including Atlantis, Tahiti, Neptune, K-2, Thunder Horse, Shenzi, Great White, Trident, St Malo, Jack and Cascade. These middle Miocene to Paleocene reservoirs are characterized by high pressure and temperature, and low natural reservoir drive energy (due to compaction and cementation). In contrast, previous production experience in younger, Pleistocene through upper Miocene, reservoirs exhibit high primary oil recovery due to significant rock compressibility and aquifer influx. The requirement for water injection to supplement reservoir drive energy, improve oil rate, and maintain oil production rates is of primary consideration in development planning for the new, ultra-deep Gulf of Mexico discoveries. Unfortunately, there is limited production experience to use as guidance.
The purpose of this study is to provide a risk-based estimate of the incremental oil from water flooding for these types of reservoirs. A parametric simulation study was performed using experimental design to calculate incremental recovery from water-flooding in ultra-deep Tertiary reservoirs in the Gulf of Mexico. Experimental design matrices were generated for both primary and water flood scenarios, based on the selected uncertainty parameters. Proxy equations for both primary and water flood oil recovery were generated from the simulation results. Statistical Monte-Carlo simulation was run using the proxy equations. By comparing the simulation results for ten year production, water-flooding case yields a recovery factor about 20 per cent higher than no-injection case based on P50 estimate.
Natural Gas Scenario in India—The Recent Upswings, Concerns, and the Way Forward
Authors: Nischal Tinku S. , Kumar Atul 
Published: October 2008

Abstract
The paper reviews and evaluates the demand – supply scenario and likely trends of the emerging gas markets in India.
With recently discovered gas reserves, the country's domestic supply is expected to increase at least double by 2011–12. The demand too is expected to increase significantly by 2011–12 in keeping with the GDP growth rate of the country. This paper focuses on three main issues; The potential and limitations of domestic gas production/supply scenario in India.Opportunities arising out of policy initiatives being taken by the Government of India though skewed development of the market due to regulated gas pricing may be a deterrent.The options available to meet the increasing demand for natural gas covering LNG imports, CBM, gas hydrates and under ground coal gasification (UCG) and opportunities for importation of natural gas through pipeline vis-à-vis the existing geopolitical scenario will also be probed into.
The paper demonstrates the upcoming opportunities in the promising Indian gas business and challenges thereof.
Hydraulic Fracture Complexity: Diagnosis, Remediation, and Exploitation
Authors: Cipolla C. L. , Warpinski N. R. , Mayerhofer M. J. 
Published: October 2008

Abstract
Recent advances in hydraulic fracture mapping technologies have provided a wealth of information on fracture propagation in numerous geologic settings. Prior to such detailed measurements of actual fracture growth, fracture propagation was either assumed to be simple (single planar fracture) or the complexity was inferred based solely on fracturing pressure data. The nature or detail of this inferred fracture complexity and how it related to actual fracture growth (real fracture geometry) could not be determined. This resulted in significant uncertainty in fracture modeling, treatment designs, and many times, suboptimum field development. This paper illustrates the application of the various methods and techniques available to diagnose fracture complexity, including simple pressure diagnostics such as G-function pressure decline analysis and sophisticated microseismic and tiltmeter fracture mapping technologies. After identifying complexity in hydraulic fracture growth, this information must be integrated with fracture, reservoir, and geologic models to properly evaluate stimulation, completion, and develop options; however, without properly identifying the nature and detail of the fracture complexity, the solution can many times be wrong – resulting in economic loss.
This paper documents field observations of different mechanisms that result in fracture complexity and the corresponding physics that govern fracture growth in these reservoirs. These field observations of fracture complexity are supplemented by and related to results from mine-back and core-through experiments to better understand the relationship between fracture complexity, rock properties, and geology. Distinguishing between the various types of fracture complexity and properly modeling these complexities (in both reservoir and fracture models) can lead to significantly different treatment designs and field development strategies. The paper includes field case histories that document how the remediation of fracture complexity can lead to stimulation success, while in other cases it is the exploitation of fracture complexity that is the key to success.
Forecasting the Productivity of Thinly Laminated Sands with a Single Well Predictive Model
Authors: Daungkaew Saifon , Claverie Michel , Cheong Boon , Hansen Steve , Leech Richard , Azam Mohd Nor Hisham Mohd , Malim Edna , Lasman Mohd. Reza , Witjaksana Renas 
Published: October 2008

Abstract
As the cost of exploration wells continue to escalate, we need more than ever to evaluate each well quickly and efficiently to improve the appraisal process and avoid unnecessary expenditure. At the same time, an accurate reservoir characterization is the key to successful reservoir development. This is especially true in thinly laminated reservoirs which exhibit vertical heterogeneity and a wide range of flow properties. Therefore, it is critical to combine high resolution formation evaluation logs and formation tests to predict the well performance prior to the production test.
We present an integrated and structured approach for calculating the productivity of a laminated clastic reservoir and we illustrate the method with a field example from Malaysia. A single well predictive model incorporates logs, rock and PVT data, and formation tests to build a flow simulation model at the resolution of the petrophysical analysis. By calibrating the high resolution flow model with dynamic test data from a formation tester Interval Pressure Transient Test (IPTT), the model can be used to predict the well performance. We investigate several key characteristics of thinly laminated reservoirs that affect the well productivity, such as vertical communication between layers. In particular, we examine the effects of clay, silt and sand laminations geometry on the reservoirs productivity. For that purpose, we comment on the information from borehole electrical images, NMR logs, single probe and dual packer wireline formation testers, and production well tests.
The workflow is fast to implement as it can be accomplished quickly and efficiently after the well is drilled, in time for planning the well completion and production tests. The high resolution simulation model permits to conduct further engineering studies, whenever required, such as designing the injection and production test for multi-layer reservoirs and water or gas coning studies.
Facilitating Data Quality Improvement in the Oil and Gas Sector
Authors: Radhay Rene 
Published: October 2008

Abstract
Seamless workflows among and within functional groups, and the resulting quality of inputs used for decision making, are common areas of concern in the oil and gas industry today. Sales of information management applications and methodologies are based on this definition of quality, which refers to the usefulness and direct availability when needed of known or high-quality information. The reality, however, is that increasing pressure to reduce costs, the volume and dynamic nature of E&P workflows, and the difficulty in measuring return on investment in addressing data quality have led to the existence of "siloed" workflows, databases of substandard quality, and resulting decision-making inefficiencies. These inefficiencies are frequently accepted as the nature of the job, both because of the difficulty in measuring their impact, and the challenge of effectively measuring the return on investment that would result from improvements. One solution to this situation is to apply technologies and methodologies that have been proven in other industries. This can help determine key performance indicators—from operational to executive levels—to enhance workflow and data quality, and can also facilitate fast cleanup and the trending of improvements and their impact on the bottom line and user perception. Modular technology also facilitates phased rollouts to minimize investment before value can be determined. Business Process Management and Six Sigma methodologies, proven in other industries, can help control cross-functional processes and the systematic reduction of defects to acceptable levels, opening the door to the establishment of industry-relevant quality benchmarks that can ultimately impact investor confidence in the oil and gas sector and within individual organizations.
Optimizing and Automating Pressurized Mud Cap Drilling with the Micro-Flux Control Method
Authors: Santos Helio , Muir Ken , Sonnemann Paul , Kozicz John , Holt Calvin 
Published: October 2008

Abstract
Pressurized Mud Cap Drilling (PMCD) is a drilling technique that has been used for over seven years in many wells where conventional drilling proved impossible or uneconomic1–5. PMCD is typically used to drill fractured carbonates, where the pore and fluid loss gradient are virtually the same, resulting in total mud losses and kicks in the same hole section. However, it is not restricted to just carbonates, it can be used on any fractured rock that is very competent in respect to wellbore stability, or formations prone to severe to total loss with good wellbore stability characteristic.
Traditional PMCD typically requires the periodic injection of sometimes large volumes of weighted mud into the annulus in order to maintain a reliable mud cap. The process is highly cyclical, often unpredictable, and can be prohibitively expensive. The process also requires highly skilled and experienced people to run it properly, an increasingly rare commodity these days.
Use of the Micro-Flux Control (MFC) method with PMCD could permit the process to be automated and controlled to a much higher level of accuracy, allowing less experienced people to confidently run the system. While continuously injecting across the wellhead, and using delta flow as the control variable, the casing back-pressure would be monitored. Casing pressure increases, indicating a loss of mud cap fluid downhole, would be automatically controlled by precise adjustment of the continuous delta flow, together with pressure monitoring, rather than by periodic injection of large volumes of fresh mud cap fluid.
This paper will briefly describe the MFC method, rig up details and operational issues. It will also describe how to apply the procedure to automate and operationally enhance PMCD, explaining the benefits when compared to the use of current procedures. PMCD case histories will be reviewed, with illustrations of costs associated with the current process and a description of how the MFC is capable of simultaneously reducing risk and costs. This increased efficiency should allow PMCD to be used when economic factors restrict its use in accessing significant hydrocarbon reserves.
First Field Applications of Downhole CO2 Measurement in Asia Pacific
Authors: Daungkaew Saifon , Harfoushian Jack , Cheong Boon , Sukahar M Wakif , Lin Tan Giok , Sun Baoli 
Published: October 2008

AbstractThe inherent uncertainty in establishing reservoir connectivity has always been an issue for reservoir management. Standard correlation methods using logs, cores and seismic data are sometimes inadequate, whereas an extended production test may be too expensive or non feasible. Increasingly, geochemical techniques are being deployed to determine reservoir connectivity based on the compositional differences in the reservoir fluid.In a number of reservoirs around the world, carbon dioxide (CO2) is a critical gas composition. Examples from two such reservoirs, one from the Browse Basin in Australia and the other from the Malay Basin in Malaysia will be discussed in this paper. The CO2 content can vary from very low concentrations in one zone to significantly high in others in the same field. In addition, accurate quantification of CO2 from reservoir fluid samples can be difficult especially if some water is also present in the collected samples. This is due to the nature of CO2 which easily reacts with water, the source of which could be mud filtrate or formation water. As a result, in a well drilled with water based mud (WBM), contamination needs to be mitigated in samples captured for the purpose of quantification of CO2 in a given reservoir.This paper presents field examples from the Asia Pacific region where a new generation Wireline Formation Tester (WFT) tool together with an advanced Downhole Fluid Analyzer (DFA) was used to quantify CO2 in real time as well as acquire high quality PVT samples. As the analyses of hydrocarbon samples from previous exploration wells within the same regions had shown significant variation in CO2 content, new and improved sampling procedures together with advanced DFA measurements were required to accurately measure and quantify CO2 concentrations in a number of reservoirs with varying fluid compositions. In this paper operational considerations and challenges of acquiring high quality PVT samples for different reservoir fluids under varying conditions are also discussed.
Impact of Effective Stress and CH4-CO2 Counter-Diffusion on CO2 Enhanced Coalbed Methane Recovery
Authors: Chen Zhongwei , Liu Jishan , Connell Luke , Pan Zhejun , Lai Zhou 
Published: October 2008

Abstract
This study addresses how the competitive impact between the effective stress and the CH4-CO2 counter diffusion-induced coal matrix swelling/shrinking affects the CO2 enhanced coalbed methane recovery. This issue is important both for the extraction of methane as an energy resource and for the safe sequestration of carbon dioxide in a coal seam. Through this study, a novel fully coupled coal deformation, gas flow, and CH4-CO2 counter-diffusion finite element (FE) model was developed and applied to the quantification of the combined net effects on coal permeability among the coal matrix swelling/shrinking due to gas displacement, pore pressure and in-situ stress. These combined effects are quantified through solving a set of coupled field equations which govern the coal deformation, prescribe the transport and interaction of gas flow in a similar way to poroelastic theory, and define CH4-CO2 counter diffusion and flow in a coal seam. Numerical results demonstrate that the evolution of porosity and permeability is controlled by the competing influences between the effective stress and the CH4-CO2 counter-diffusion induced volume change. This achievement extends our ability to quantify the opposite impacts of effective stress-induced and CH4-CO2 counter diffusion-induced coal matrix deformation on the CO2 enhanced coalbed methane recovery under field conditions.
Intelligent Fields Management at Woodside: A Low-Cost Step Improvement in Field Management Using Off the Shelf Technology
Authors: James Bruce , Kerr Kevin A. , Lim Stephanie , Lewandowski Ed , Knight Craig , Bell Richard 
Published: October 2008

Abstract
Using improved integration, data efficiency and more informed decision making, Woodside's Intelligent Fields Management (IFM) has created a step change improvement in the way the Cossack-Wanaea-Lambert-Hermes (CWLH) fields are managed. There is tremendous value in IFM in numerous and often unexpected places. However, the greatest value likely lies within the improved integration of data and work practices and longer-term reservoir management. The benefit-cost ratio of IFM on the CWLH fields is likely in the order of ten to one. This paper demonstrates what a mid-sized oil and gas company can accomplish within 12 months and at relatively low-cost using off-the-shelf technology and starting with little pre-existing knowledge.
CWLH is four oil fields with 11 subsea wells tied back to a floating production storage offtake (FPSO) vessel located offshore on the North West Shelf of Australia. The initial focus of Woodside's Intelligent Field Management program is on near-term field management issues, including reducing well testing, daily optimisation, production allocation, and managing sand erosion. Woodside's IFM program is currently being implemented on two other oil assets, with an expansion to gas and longer-term reservoir management planned for later in 2008.
The Petroleum Experts' Integrated Field Manager™ is the calculation engine used in the IFM program, allowing for custom workflows to be automated and scheduled. For example, workflows have been created that can run every 30 minutes and automatically identify elements of an integrated asset model, where measured behaviour significantly diverges from calculated behaviour. Powerful visualisation for interpreting data, particularly across disciplines, was critical for success and was realised through ISS Group's Babelfish™ web based viewer.
Successful implementation relies on a highly motivated interdisciplinary team, dedicated IT and management support and close interaction with asset teams. Long-term success will require ongoing IT and super-user support.
A Case Study in the Successful Design and Implementation of Frac-Pack Treatments in a Challenging Workover Environment in Malaysia
Authors: Reza Mohd Shah , Shamsuddin Seri'ainatrah , Juan Lim Jit , Pathmanathan Indran 
Published: October 2008

Abstract
ExxonMobil Exploration & Production Malaysia Inc. (EMEPMI) operates a non-associated gas field in the offshore Malay Basin which produces from deep consolidated sands. In 2006, EMEPMI undertook a 2-well recompletion program to develop a shallower unconsolidated sand which required downhole sand control. This paper details the challenges encountered and solutions developed to successfully install frac-pack sand control treatments. The recompletion challenges included limited data to design the treatments, tight space constraints limiting frac-pack equipment capability and a platform hazardous zoning requirement that created logistical difficulties. The paper will also describe the various sand-face completion technologies investigated before the recompletions as well as the lessons learnt from these experiences that will be applied to future treatments.
These were the first successful frac-pack sand control installations in EMEPMI's history. The sustained prolific gas production obtained from these wells affirms the success of the completion method. In addition, sand-production monitoring further reinforces that downhole sand control has been achieved, since only a small amount of ultra fine particles that have no negative impact on production or surface equipment have been detected. These positive results highlight the importance of operator technical/operations personnel and service providers working as a team to develop the most appropriate solutions to the technical and operational challenges encountered.
A New Syngas Production Process for GTL
Authors: Suehiro Y. , Watanabe Y. , Sugimoto A. , Yokoyama K. , Ikeda K. , Inoue N. 
Published: October 2008

Abstract
Japan Oil, Gas and Metals National Corporation (JOGMEC), JGC Corporation and Osaka Gas Co., Ltd have been developed a new syngas production process, Advanced Auto-Thermal Gasification (A-ATG) process, consisting of a new auto-thermal reforming catalyst with ultra-deep desulfurization of natural gas. We verified A-ATG process through 2,000 hours syngas production operation at pilot plant of which capacity was 65 BPD-GTL equivalent. This paper shows result of pilot plant operation and discussion including economics, environmental parameters and a future application of this system.