bluuebunny/crossref_metadata_2025_split huggingface dataset:
Accurate Reservoir Evaluation in Exploration Gas Wells: A Case Study in Malaysia Basin
Authors: Hassan Rozlin , Malaysia Lundin , Haddad Sammy , Wa Wee Wei , Johan Zailily , Lim Lee Chin 
Published: May 2016

Abstract
Reservoir fluid composition and reservoir parameters characterization are fundamental for the accurate reservoir description during exploration phase and successful reservoir management in gas field development planning. Key reservoir fluid parameters namely hydrocarbon composition and Carbon Dioxide (CO2) are essential input to comprehensive production and reservoir engineering studies.
The paper presents the exploration work done through three gas wells campaign in two main Malaysia basins. The formation is mainly thinly laminated sand-shale beds and the main objective for the operator is to acquire an early and quick identification of hydrocarbon prospect for appraisal wells planning. With that, compared to conventional PVT lab analysis which can easily take weeks to months to complete and full scale DST that offers higher operational complexity and cost, downhole fluid analysis was deployed.
Downhole fluid analysis has successfully identified the reservoir fluid composition and properties for different fluid types. In this offshore Malaysia basin, high CO2 content was not expected geologically, high CO2 was measured in several sands of interest and this early identification on non-hydrocarbon prospect avoids unnecessary cost, time and operational risks. This work presents the successful downhole reservoir fluid identification in mobility range of 23.2 to as high as 5263.8 md/cP. The methodology, applications and suggested best practices applied throughout the campaign are presented in this paper.
Quality Assurance of Carbonate Rock Special Core Analysis - Lesson Learnt from a Multi-Year Research Project
Authors: Ma S. Mark , Belowi Ali , Pairoys Fabrice , Zoukani Ahmad 
Published: May 2016

Abstract
Core data has historically been used as the ground truth in many upstream applications, such as formation evaluation, geological modeling, and reservoir simulation. The importance bestowed upon the data requires that core analysis programs are properly designed and the data is thoroughly quality controlled. Otherwise, a high percentage of the data, especially from special core analysis (SCAL), may not be usable. To design a fit-for-purpose program and produce quality results, potential issues related to the analysis of the targeted reservoir rock and fluids need to be fully understood and taken into account. Many lessons have been learnt from a multi-year project studying drainage and imbibition electrical properties in carbonate rocks, chief among them are related to rock cleaning, porous plate preparation, and test equilibrium conditions.
Results generated in this study show that conventional cleaning may be sufficient for a porosity measurement provided that rock is not extremely heterogeneous. Specially designed cleaning procedures and solvents should be applied for wettability restoration as demonstrated from various wettability measurements. In using porous plate for resistivity index (RI) tests, the main challenges are to prepare the porous discs to oil-wet and flow crude oil through them. Special procedures have been developed to address these challenges successfully. In performing equilibrium RI tests, data shows that a test cycle may last for many months, or even years, and often may be terminated prematurely due to equipment/ sample failures. This issue can only be resolved by adopting a non-equilibrium method with in-situ saturation monitoring and/or numerical simulation algorithms.
Findings from this study can help others to better understand some of the key issues in dealing with carbonate rocks in the core analysis laboratory, thus design a proper SCAL program to produce quality SCAL data.
An Integrated Approach to Evaluate the Further Development of the Changbei Unconventional Tight Gas Reservoirs
Authors: Du Kuifu , Schaeftlein Susanne , Mahiya Glenn , Thum Matthias , Marden Roy , Mohamed Taha , Yang Yatao , Hong Hong 
Published: May 2016

Abstract
Shell and PetroChina have been successfully developing the Main Changbei P1S2 QA Reservoir using the advanced technology of openhole dual lateral horizontal wells since 2005. The scope of this project has been expanded to further develop the Changbei Main Reservoir and also to appraise and develop the Unconventional tight gas Reservoirs. The Unconventional tight gas Reservoirs have not been commercially developed to date and are geologically very different from the Main Reservoir. The team employed front end loading and decision based modelling to manage the complexities of essentially developing a green field within a brown field, and unconventional microDarcy reservoirs above and below a more conventional milliDarcy reservoir. The field was divided into type areas based on reservoir quality and development maturity. The Main Reservoir modelling approach is conventional but the Unconventional Reservoirs will require single-well multi-reservoir box models to facilitate probabilistic uncertainty work flows and type curve generation. Synergies between the Main and the Unconventional Reservoirs have also been considered.
World First: Drilling with Casing and Riserless Mud Recovery
Authors: Peyton J. , McPhee A. , Eikemo B. , Evans H. , Utama B. 
Published: May 2016

Abstract
This paper discusses the planning and operational aspects of drilling with casing (DWC) combined with riserless mud recovery (RMR), along with the benefits experienced compared to conventional drilling. The process of identifying and mitigating risk when applying new technologies to ensure a first time success will also be discussed.
The Dampier Sub-Basin offshore Australia presents major challenges to tophole operations when drilling through the problematic 'Bare Sands.' The formation is composed of highly porous sand in which lost circulation is often encountered. Severe losses prevent sufficient hole cleaning, leading to packoffs around the bottomhole assembly (BHA) and stuck pipe. The formation is also interbedded with soft sand and hard cemented layers, causing severe torsional vibration and twistoffs in the BHA. Well designs and operations had been altered, incorporating larger hole sizes and control drilling to reduce packoff risks. Multiple bit runs were also optimised for each formation. This method reduced the occurrence of junked wells at the cost of individual well performance.
DWC promised to enhance performance by drilling the interval in a single run and reducing the number of trips. However, as applications of new technology encompass risk and uncertainty, the operator performed extensive analysis to quantify the likelihood and cost of failure modes and the expected reward. A key finding of the analysis was a necessity to mitigate stuck pipe. RMR offered a cost-effective method of enhancing hole cleaning to avoid this hazard. The operation was performed from a semi-submersible rig, reaching a world record depth in technical limit time without hole condition problems.
The methods discussed ensured the successful application of multiple new technologies, achieving a world record and technical limit performance. DWC combined with RMR is a world-first, and offers an effective solution for tophole drilling in the basin, and for similar basins worldwide.
Managing Chemical EOR (ASP) Effects on Formation Damage and Flow Assurance in Malay Basin, Malaysia
Authors: Yee Hon Vai , Bt Halim Nor Hadhirah , Bt Salleh Intan Khalida , Bt. A.Hamid Pauziyah A. , B Sedaralit M Faizal 
Published: May 2016

Abstract
The venture into various EOR process applications has been aggressively undertaken by industrial oil players to satisfy the ever-increasing world energy demand. Success of an EOR project is also governed by understanding and readiness in handling the associate EOR induced formation damage and flow assurance issues. Hence the considerations of these issues must be given great attention in the EOR project master plan.
Each EOR process application is unique and the associate formation damage and flow assurance issues are different. This paper examines the mechanisms, preventions and mitigation options for chemical EOR process induced formation damage and flow assurance issues. Fluid chemistry changes due to fluid-fluid and fluid-rock interactions among the EOR injectants, reservoir fluids and rock matrix, lead to many undesirable injection and production issues. A case study on the R&D experience of one of the major chemical EOR fields in the Malay Basin is presented. Laboratory analyses to understand and predict the severity of these issues are discussed. The major sources of problems are identified and their impacts on the success of the EOR project are discussed. A number of solutions have emerged to address these challenges. Recommended solutions are considered based on practicality, performance and economic viability.
Careful coordination during EOR project planning in handling the flow assurance and formation damage challenges and a more proactive approach to address them is our long term strategic focus which will bring significant efficiency and profitability benefits.
Corporate Social Responsibility- Methodologies, Performance and Management in Oil and Gas Industry: Case of a leading E&P Company in Colombia, South America
Authors: Baskaran V.K. , Dani K.C. , Pokhriyal S.K. , Fernandez G.J. 
Published: May 2016

Abstract
Mansarovar Energy Colombia Ltd. (MECL), a JV formed by India's ONGC and Chinese oil firm Sinopec, is engaged in the exploration, development and production of oil and natural gas in Colombia. Our firm owns interests in 11 fields across Colombia's Middle Magdalena basin, through association contracts with Colombia's state oil company Ecopetrol. Velasquez oil field is located in central Colombia about 160 km far away from the capital Bogota. Discovered in 1946, the Velasquez oilfield has an area of 32 km2 and was put into production from 1947.
The Valley with 45,000 sq. km has 33 municipalities, 91 rivers and approximately 1,200,000 inhabitants who make this region a potential for alternative projects that will generate social development with equity and allow improved quality of life in this prosperous region.
MECL defines CSR as "The commitment assumed for the contribution to the development, welfare and improving the quality of life for employees, their families and the community at large". Under this commitment, the company avoids any negative impact of its operations over people and its surrounding area. The management is a five stage process: Diagnostics, programs and project planning, execution, tracking and monitoring and evaluation of results.
The general objective of MECL is contribute to the economic development of the population in the vicinity of Velasquez through the articulation and enforcement of contracts and agreements between private companies, state and community efforts to articulate economic, operational and sustainability to find the social, community, business and environment. Promoting social and territorial development through investment in education, health, environment using basic mechanisms of institutional cooperation, management and community participation, establishing new revenue-generating alternatives to low-income are some of our specific objectives. Our activities include literacy programs, drug prevention workshops, cultural projects, business development training, sexual health workshops, sports, education workshops for school community (parents, teachers and students), provision of school kits to students, preventive medicine health training etc. MECL invested 1.74 million USD to fulfil its responsibilities during the year 2011.
A Case Study of Detailed Computational Fluid Dynamic Modelling of Coupled Wellbore and Subsurface Multiphase Reactive Flow
Authors: Tang Qing , Tsai Kuochen , Pollard Richard , Harvey Albert , Srinivasa Mohan 
Published: May 2016

Abstract
A novel concept of circulating molten salt (CMS) through a subsurface formation has been developed for the purpose of in-situ upgrading (IUP) of heavy oils into lighter transportation fuels, in pursuit of its potential to substantially reduce power expenditures and CO2 emissions during the IUP process. The CMS system can utilize molten nitrate salt to transfer heat from a surface heat source down to the hydrocarbon (HC) bearing reservoir via a system of underground pipes, essentially creating a subsurface heat exchanger. Nitrate salts are known to be strong oxidizers and can react exothermally with various hydrocarbon constituents in the subsurface under certain conditions. Detailed Computational Fluid Dynamics (CFD) simulations were carried out to evaluate the consequences of an accidental release of molten nitrate salt from a failed pipe and into the surrounding formation rock. Modeling results have been used to assess:the temperature and pressure build up in the near wellbore region; andthe propagation of a reaction front in the formation and its impact on neighboring heater/producer wells.
Extensive sensitivity analyses on salt temperature, reaction rate constants, and time of occurrence were performed. The simulation results indicate that the reaction progress is likely to be mass-transfer controlled rather than kinetically controlled under subsurface conditions. Both pressure and temperature build up are likely to be moderate in the event of a large release of molten salt. The damage that a moving burning front in the formation may cause to neighboring heater pipes appears to be manageable as long as sufficient flow rate is maintained in these pipes.
Recognising and Avoiding Water-Production Intervals Using Integrated Petrophysical Methods: A Case Study from the Piceance Basin, USA
Authors: Wu X. , McHarge J.L. , Awwiller D.N. , Devlin B. 
Published: May 2016

Abstract
A regionally extensive tight-gas accumulation in the Cretaeous age Mesa Verde Group of the Piceance Basin, Colorado, USA has been actively developed for over a decade. Daily production has increased from under 200 MMCFD in the year 2000 to over 1 BCFD currently. However, in some parts of the basin, the commercial development of the asset is challenged by water production.
The tight gas reserves occur in a stacked, multi-sand system. It includes over 100 stacked reservoir targets distributed over approximately 5,000ft of formation vertically. Water can be produced from any of these targets geographically. Produced water can cause serious wellbore hydraulic issues and also increase water disposal cost. Therefore, recognizing and avoiding high water production zones before hydraulically fracturing is critical.
A workflow for evaluating water-production risk has been developed. The workflow includes 1) deriving reservoir properties (porosity, water saturation, etc.) from open-hole and/or cased-hole logs, 2) calibrating the log measurements with a robust core-based, grain-size-dependent permeability prediction model, and 3) using water saturation in conjunction with permeability to evaluate the likelihood of low capillary or imbibed water for individual sands. This gives a qualitative analysis of water risk on a cross-plot of permeability versus permeability-water-saturation separation (k-Sw screening) with no water production risk (bound water) to high water production risk. The k-Sw screening concept has been verified with logs and production data from over 50 wells in the northern part of the basin. The workflow helped decrease water production thereby improving the economics of the tight gas play.
Solvent-aided Steam-flooding Strategy Optimization in Thin Heavy Oil Reservoirs
Authors: Zhao David W. , Wang Jacky , Gates Ian D. 
Published: May 2016

Abstract
Stochastic optimization based on a simulated annealing method were carried out to determine the optimum steam and steam-solvent flooding strategies in thin (4 m) heavy oil reservoir both in the absence and presence of a bottom water zone. The steam injection pressure optimization case determined a technically feasible operating strategy. However, the cumulative energy to produced oil ratio (cEOR) realized from the optimized process is high. In comparison, the solvent-aided steam optimization case achieved an operating stratety that obtains a much lower cEOR and cumulative water-to-oil ratio (cWOR) than those in the optimized injection pressure-only strategy. We observed that a solvent channel forms at the top of the reservoir after breakthrough of solvent to the production well. The formation of the solvent channel led to oil-solvent mixing at the periphery of the channel as well as heat transfer to oil beyond the channel, which leads to better recovery performance. In the the presence of a bottom water zone, the optimized steam injection pressure optimization strategy was found to perform poorly. However, the optimized solvent-aided strategy achieved superior economics. With solvent injection, the presence of the bottom water zone enhanced mixing of solvent and oil yielding better oil recovery performance.

Background
In Western Canada, about 80% of heavy oil resources are found in reservoirs less than 5 m thick (Adams 1982). Although currently commercial thermal-based techniques such as Steam-Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) are highly successful for recovering bitumen and heavy oil from thick pay zone (&gt; 15 m), their application in thin heavy oil (&lt;6 m) reservoirs are generally not thought to be economically viable. This is due to the high steam-to-oil ratio (SOR) which caused by significant heat losses to the overburden relative the amount of heat delivered to the oil which renders the processes uneconomic. Cold production (CP) employs small energy input. However, the average recovery factor is typically low, usually, between 3 to 8% of the Original Oil In Place (OOIP) (Adams 1982). By employing so called Cold Heavy Oil Production with Sand (CHOPS) technique, the recovery factor can reach as high as 15% (Pan et al. 2010). However, the formation of wormholes during CHOPS operation creates new challenges for applying follow-up processes to recover additional oil beyond CHOPS.
Flow Assurance Study for a Subsea Production System with a Large-Scale Seabed Storage
Authors: Kim Juneyoung , Choi Younseok , Choi Inhwan , Kim Jakyung , Park Su-youl , Seo Yuteak , Chang Deajun , Chang Kwangpil 
Published: May 2016

Abstract
This study suggests a new concept of the subsea production system based on a large-scale seabed storage tank that stores the well fluid temporarily and later transfers it to the shuttle tanker through the riser. This concept was assessed to have advantages of reduction in the floater size, freedom from transportation distance, insensitivity to sea depth, and environmentally friendliness over the conventional deepsea solutions. Several flow assurance hazards for this system were expected, and appropriate design measures and operational methods against the hazards were suggested. A feasibility study was performed for an oil field which was located at 2190 m deep producing the well fluid of black oil type. The capacity of the seabed storage tank was considered to be 300,000 m3. Simulation results showed that riser diameter should be 19 inch and the insulation layer should be thicker than 100 mm.

Introduction
Subsea production systems have been devolving rapidly over last decades. At first, a fixed type platform was developed for shallow water field. At the early stages, the jacket structure platform was used for production. Later follwed the gravity based structure which withstood external force with self-weight and the jack-up rig platform which could regulate own height with hoist. As the sea depth increased, the compliant type platform was developed. At first, the guyed tower was used for production. Continuously, the tension leg platform which was moored by tendons was followed and the spar platform which was a large-diameter, single vertical cylinder bouy developed as an alternative to conventional platforms. Recently, floating type platforms, like semisubmersible platforms and FPSOs were developed for deep water field.
A Proactive Approach Towards Optimising Drainhole Placement Using "DTB" Technology in an Area Under EOR - A Success Story from Western Onshore Field, India
Authors: Singh R.L. , Keot Chandan Jyoti , Kumar N. Sanjay , Majumdar Chandan , Singh Amit Kumar 
Published: May 2016

Abstract
Field X is located in the northern part of Cambay basin, western onshore India. Sand-1 is the main reservoir unit in this field. Primary recovery is low here because Field X is located in the region's heavy oil belt. To increase the recovery factor, thermal EOR technique - Insitu Combustion, has been implemented in various parts of this heavy oil belt. Insitu combustion reduces oil viscosity but at the same time produces residual gases. These residual gases, called "Flue gas", accumulate as pockets in the reservoir top. The thermally altered low viscous crude can be produced efficiently through horizontal drainholes by maximizing reservoir contact and sweep radius.
Placing a horizontal drainhole in this field is a challenge in itself because the drainhole has to be maintained at a safe distance from the flue gas pockets on top to prevent premature gassing out and also at a safe distance from bottom shale.
As a solution to this challenge, "Distance to Boundary" (DTB) technology along with LWD was introduced for the first time in Field X in Well X. "DTB" technology detects the resistivity contrast at a shale-sand interface and maps the shale boundaries while drilling. The well was landed ~10m below reservoir top using LWD measurements to maintain a safe distance from flue gas pockets on top. It was decided to place the drainhole about 3m above reservoir bottom to stay away from bottom shale. The final result was a spectacular success with 311m of drainhole drilled with 100% stay in target reservoir zone. "DTB" technology tracked lower shale from ~3m and trajectory was maneuvered in conjunction with the structural changes to maintain an average distance of 3m from bottom. LWD data was used to verify sweet zone throughout the drilled interval.
This paper illustrates an exemplary case study which opens new and exciting possibilities for application of LWD and "-DTB-" technology in field X for further field development plans.