bluuebunny/crossref_metadata_2025_split huggingface dataset:
Waterflooding Optimization: A Pragmatic and Cost-Effective Approach to Improve Oil Recovery from Mature Fields
Authors: Lu X. G. , Xu J. 
Published: October 2017

Abstract
This paper presents selected effective technologies and best practices to improve oil recovery from mature fields through waterflooding optimization. These technologies are proved practical, applicable and cost-effective. They can effectively facilitate further development of mature fields, which is more important than ever before in the current economical down-turn environment.
First, this paper summarizes and discusses several pragmatic approaches to optimize waterflooding of sandstone reservoirs. These methods have proved to be beneficial for expanding sweep, thus increasing ultimate recovery. Next, the authors introduce two methods to evaluate the effectiveness of application of these technologies, which can support both qualitative evaluation of the successfulness of the applications; and quantitative estimate of incremental recovery. Finally, this paper illustrates the best practices of each waterflooding optimization technology and the associated reservoir dynamic performance.
Waterflooding optimization aims at expanding volume sweep to recover bypassed oil in undrained areas or remaining oil in poorly swept areas. The main established approaches include (a) zonal water injection, (b) changing direction of fluid flow, (c) subdividing injection-production unit, (d) water shut-off to improve areal sweeping efficiency, and (e) cyclic water injection. These techniques are particularly applicable to multi-layer, vertically and laterally heterogeneous reservoirs at the high water-cut production stage. One best-practice example shows that converting comingled water injection into zonal injection has successfully arrested production decline, and resulted in an 11.8% incremental recovery. In another reservoir with 98% water cut and 54.5% recovery of changing injection direction by modifying well pattern has led to a 10% incremental recovery by. In still another example, subdivision of injection-production unit combined with infill wells has achieved incremental recovery ranging from 9% to 20%. A further case illustrates that, compared with continuous water injection, cyclic injection had led to reduced water production, lowered water-cut and increased recovery, and resulted in an incremental recovery of 1.84% EUR.
To conclude, maximizing reservoir sweep efficiency is the core step of waterflooding optimization. The techniques and best practices discussed in this paper possess both technical and economic viability. Effective application of those methods is an essential part of profitable reservoir management of mature fields.
Methodology of Compartmentalization Analysis for Modelling - Mereenie Field, Northern Territory
Authors: Nguyen T. T. , Nguyen L. A. , Perdomo G. E. 
Published: October 2017

Abstract
Explored in 1964 and first oil production launched in late 1984, Mereenie oil and gas field is the largest onshore oil field in mainland Australia. Although the production within the Eastern region has been in decline, an appraisal and development drilling project is expected to extend the life of the field. Therefore, a good understanding of dynamic compartmentalization through validation of material balance modeling would address current production planning and monitoring focused in the current oil production formation, Pacoota 3. This study could be the foundation for future development of the western part of the field.
Over 30 years of production and an enhanced oil recovery scheme which involved periodic injection from abundant gas within the upper formation, Pacoota 1; the producing oil formation has yet had any in-depth study of a dynamic compartment within the production time scale. The main objective of this study is to provide an analytical framework for dynamic compartmentalization. This framework was developed to capture the complexity in completions strategy and in the injection period. In total, six compartments across the Eastern Pacoota 3 formation were successfully identified and confirmed through modeling. However, uncertainties in structure and limited data at the West have contributed to production simulation's shortcomings.
It was found that compartmentalization in Mereenie is a combination of variables; those are a natural baffle, fault sealing, injection rate, and drainage radius; while structural faults have a primary role in decreasing the permeability and mobility of oil, causing discontinuity throughout the formation.
Optimization Chemical Flooding Methods to Enhance Oil Recovery of Strong Heterogeneity, High Temperature and High Salinity Reservoirs - Case Study of Shengli Oilfield
Authors: Lu Nu , Hou Jian , Liu Yongge , Guo Lanlei , Yuan Fuqing , Wei Cuihua , Liu Yifei 
Published: October 2017

Abstract
Chemical flooding usually cannot achieve good oil displacement effectiveness in strong heterogeneity, high temperature and high salinity(SH/HT/HS) reservoir. Through a typical SH/HT/HS reservoir in Shengli Oilfileld, this paper builds a screening method to select the optimal chemical flooding approach with best economic effectiveness for SH/HT/HS reservoir.
Numerical simulation based on field data is used to screen chemical flooding approaches. First a novel index called Gini coefficient of the injection profile(GINIP) is proposed to preliminarily select chemical flooding approaches. Different chemical flooding approaches have different GINIP turning points. Oil recovery drops sharply when GINIP exceeds turning points. And then economic effectiveness is considered. Economic effectiveness is expressed by the ratio of enhanced oil weight and chemical agent cost(t/dollar). Salinity, calcium-magnesium content and temperature influence the economic effectiveness of chemical agent. So an optimal chemical flooding is selected for specific SH/HT/HS reservoir by the above two steps. According to different agents, heat-resistant and salt-tolerant chemical flooding can be divided into Surfactant-Polymer(SP), SP-Preformed Paticle Gel(SPPG) and Polymer-Preformed Paticle Gel(PPPG). The GINIP turning point of SP is 0.76. SPPG is 0.82 and PPPG is 0.85. The GINIP of GDCR1 block in Shengli Oilfield is 0.6. So SP, SPPG and PPPG can all be applied. Salinity of GDCR1 block is 10000mg/L. Calcium-magnesium content is 100mg/L and temperature is 70°C. The economic effectiveness of SP is 16.34t/t. SPPG is 18.46t/t and PPPG is 15.02t/t. So SPPG is the optimal chemical approach for GDCR1 reservoir. In recent five years, SPPG flooding applied in GDCR1 block enhanced current oil recovery 5.6%(total oil recovery over 60%) and decreased maximum water cut over 19.7%. Compared with other nearby same blocks, this performance is very good. This indicates that the screening method presented in this paper is effective and accurate.
An Integrated Geomechanical Approach for Successful Drilling through Coal in Peninsular Malaysia and Offshore Vietnam
Authors: Chatterjee Avirup , Ghosh Amitava , Bordoloi Sanjeev 
Published: October 2017

Abstract
Past drilling of vertical and moderately deviated development wells in offshore Peninsular Malaysia and Vietnam has proven to be challenging. Drilling experience in the development wells highlighted the issue of wellbore instability in the respective areas, particularly though coal seams. Numerous lost-time incidents related to wellbore instability-related problems were experienced, ranging from tight hole (remedied by reaming) to overpull, pack-off followed by stuck pipe, fill on-bottom to difficulties in running casing, and coal cavings to high gas associated with drilling breaks. These problems were observed particularly when drilling through the weak shales with interbedded unstable coals.
Coal instability often does not respond to the same remediation used in shale, where we usually simply raise the mud weight to reduce the compressional hoop stress below the strength of the rock. Borehole collapse or breakout may still occur when the coal cleats and natural fractures allow the drilling fluid filtrate to invade despite using an optimum mud weight. This results in pressurization of the near-wellbore region and loss of effective mud weight support for coal stability. All the wells in the respective areas were drilled with WBM and so drilling performance benchmarking with other drilling fluids was not possible in the study area. Faced with continual NPT, a geomechanical study was initiated to mitigate the coal related wellbore instability problems. The recommendations arising from the comprehensive geomechanical and drilling experience analyses have been implemented to improve performance during subsequent development drilling.
This paper highlights the importance of integrating geomechanics with proper drilling practices when developing strategies to mitigate unstable hole problems, especially related to coals. A full-scale geomechanical model was developed, validated and updated using logs and drilling data from wells in both the areas. The drilling experiences, rock mechanical properties, in-situ stresses and formation pressure in both the areas are presented and discussed in detail. A detailed recommendation on the drilling strategy through coal and the associated uncertainties was implemented. Utilization of geomechanical results from the two studies and the approach adopted in the development of drilling strategies helped to determine recommended optimal mud weight programs for the future wells.
Subsequent drilling campaigns have all been successful by incorporation of the entire risk and mitigation plan. This included a generalized road map with a protocol for drilling through coal, tripping and back reaming during drilling, pre-drilling and post-drilling. This effort, together with optimized drilling fluid design and the correct mud weight based on previous drilling experience as per recommended wellbore stability assessments, helped in two recently drilled wells in different areas with reduced NPT.
Managing Mature and Unconventional Fields
Authors: Ahmad Aladasani , Qutaiba Okasha , Nandkumar Aravind , Ali Ameen , Kunal Sen , Al Dushaishi Mohammed 
Published: October 2017

Abstract
This paper presents a critical review of planning systems for hydrocarbon exploration and production development (E&PD) companies. Traditional planning systems are no longer suitable to manage maturing reservoirs, capital-intensive projects, challenging reservoirs and growing development costs in low oil price regimes. The development of maturing oil fields and unconventional hydrocarbon resources requires dynamic development plans that are rigorously aligned with the targeted performance and adopted strategy. Traditional planning systems are no longer suitable because they lag in reacting to risks and opportunities.
This paper describes a system that would reconcile development plans with business performance and constantly facilitate any required change in strategy. The triangular alignment of development plans with performance and strategy is quantitatively rigorous since it must encompass subsurface and surface operational risks including HSE risks and development cost. Planning system validation is required for gap resolution and alignment of the planning system elements. The use of analytics is a requirement to validate operational plans, validate the strategic plan and measure performance. Organizational structure, capabilities and compliance in maintaining the Planning System Integrity must be managed in par with the strategy milestones.
Modelling the Impact of Reservoir CO2 on Polymer Flood Performance in Aishwariya Field
Authors: Mishra Sudhakar , Pandey Amitabh 
Published: October 2017

Abstract
Fatehgarh reservoirs in Aishwariya field, located in Barmer Basin of Rajasthan India, have very high CO2 content; ~80-90 mole% CO2 in the gas phase and ~10-40 mole% CO2 in the oil phase. Formation water sample has shown CO2 concentration of ~7500 ppm with a pH of ~5.6. The oil is moderately viscous and aqueous based chemical EOR techniques like polymer/ASP flooding have been identified as the most suitable for Aishwariya's field conditions. The presence of CO2 decreases the pH of a system. The viscosity of polyacrylamide polymers is known to decrease with reduction in pH; however, to the best of author's knowledge, commercial simulators do not have any method to directly model this viscosity dependence on pH. Therefore, a procedure was developed to capture the impact of CO2 on polymer in-situ viscosity in a reservoir simulation model.
An EOS based PVT model was first developed using PVT data from the field. This EOS was then used in a commercial compositional simulator to calculate the phase distribution of CO2 during an injection process. The liquid-liquid partitioning coefficient for CO2 was calculated as the ratio of CO2 mole fraction in oil phase to that in water phase. A similar model was then created in an "advanced process" reservoir simulator which modelled component distributions based on partitioning coefficients. For simplicity, the solution gas was assumed to be entirely composed of CO2. The CO2 component was defined as part of the aqueous phase instead of the default oleic phase. Data which related polymer viscosity to pH were used to create a "Viscosity-pH" table; other data permitted the construction of a "pH-CO2 concentration" relationship. Linking these two tables together allowed the development of a "Viscosity-CO2" function. Defining the CO2as an "aqueous phase salt component" enabled us to model the polymer viscosity variation with CO2 concentration. Simulation runs were then carried out both with and without the effect of CO2 on polymer viscosity and the results were compared.
The developed approach captured the impact of CO2 on the simulated polymer flood performance. It permitted us to quantify the amount of additional polymer that would be required to compensate for polymer viscosity loss in the presence of CO2. It helped to improve our confidence in polymer flood performance predictions for this field despite the presence of a significant amount of CO2.
The paper presents a step by step approach of utilizing commercially available simulation softwares to model the impact of in-situ CO2 on polymer flood performance. The proposed method can be applied in fields with high concentrations of CO2. The method can be extended for fields with lesser concentrations of CO2.
Sustaining the Barrels - Making Well Intervention More Affordable
Authors: Mokhtar S. R. , Wibisono R. , Zakaria M. , Shabudin A. 
Published: October 2017

Abstract
For the past several years, crude oil prices have fallen at an unprecedented level which put the oil and gas industry at the downturn state. As a result of this downturn, the industry responded by lowering down CAPEX and OPEX investment to find new reserve, sustain or increase production and arrest production decline rate. Additional production by means of drilling becomes more challenging as the investment cost especially in offshore environment is very high. One of the way that that most of the operators choose to maintain and/or arrest decline of production is by intensifying the well intervention activities. However, the legacy of high oil price has caused decades of value leakages in well intervention that need to be reduced to reflect low price environment.
Malaysia Petroleum Management (MPM), the regulatory arm of PETRONAS, spearheads a nationwide Cost Reduction Alliance (CORAL) program to reduce overall upstream industry spending in Malaysia. One of the focus of CORAL program is to challenge the value leakages in well intervention by launching Lean Well Intervention initiative. The Lean Well Intervention initiative has an objective to reduce overall well intervention spending in Malaysia by 3 % in the first year and total of 10 % within the next 4 years.
This paper outline the journey of CORAL Lean Well Intervention program in Malaysia. MPM performed detail analysis of overall well intervention spending in Malaysia and summarized three key areas that shall reduce the cost but at the same time do more well intervention activities to maintain production and/or reduce decline in production. The selection method of the three key areas with criteria to have sustainable cost reduction shall be described in detail as well the implementation phase that emphasizes on communication with all the key stake holder. Another challenge is to ensure that the reduction in cost and improvement in efficiency will be sustainable and will not be reversed if there is an increase in oil price. These three key areas are; optimizing well intervention operating model, selection of fit for purpose technology, and contract management.
As the result of these three key areas, total of more than 20 % cost reduction was achieved in the first year of implementation. This has allowed more well intervention activities to be executed and contributed higher production gain from the previous year. As a closure, the result of the program with comparison of previous year cost spending, activity level, and production generated and how it is finally embedded in the system as business-as-usual practice shall be discussed at the end of the paper.
Optimal and Fast Drilling Technology for Shale Gas Horizontal Well and Its Application
Authors: Zhang Jincheng , Zhou Haobo , Zang Yanbin , Niu Xinming 
Published: October 2017

Abstract
SINOPEC has constructed the first commercial and scaled development shale gas field in Fuling of China, the annual productivity of which is 5 billion cubic meter until the end of 2015. And the other 5 billion cubic meter annual productivity construction of this shale gas field is in progress. The problems faced in this location are the complex geological environment, mountainous environment, the shale gas reservoir characteristics and the reservoirs buried so deeply (vertical depth&gt;3000m). Therefore, the mud loss collapsing and gas kick are very common problem encountered while drilling, the ROP decreased greatly and the cost of drilling operation increase rapidly. With falling oil and natural gas prices, greater efficiency and excellence in well construction is called for, the optimal and fast drilling technology and successful application for shale gas horizontal well in Fuling is described.
Firstly, a "mountainous well factory" design method for shale gas horizontal well design was established, in which the terrain and geography condition, the well trajectory control capacity and the limit of horizontal extension were all taken into account, through which the design of batch operation scheme and optimal well patterns can be obtained easily. Secondly, for improving the productivity of single well and reservoir rate of drilling, a borehole trajectory design model was developed based on the natural drift law of the formation, in which the anti-collision was took into account, and through which all of the optimal trajectories for entire horizontal well group can be designed easily. Moreover, an integrated optimal and fast drilling technology that combined bits optimization, trajectory controlling and BHA optimization was developed based on the analysis of formation characteristic, based on which the best drilling optimal plan can be formulated.
The optimal and fast drilling technique has been applied in several mountainous well factory platform in Fuling shale gas field of SINOPEC. And through the novel technology for shale gas horizontal well group, the drilling show that the ROP of these wells were improved about 182%, the drilling cycle were cut down more than 50% and the cost of well construction was decreased more than 30%.
This study will presented the novel optimal and fast drilling technology for shale gas horizontal wells, which includes the mountainous well factory design method, the improved well trajectory design and control method, and the novel technology application in shale gas drilling design and construction. Through the application of the optimal drilling technology, the results show that the ROP in shale gas horizontal well drilling has been improved obviously, the drilling cycle and the cost of well construction was decreased greatly.
Developing Enhanced Mechanical Properties of Solid Expandable Systems and Its Evaluation Method for Well Drilling Preparation
Authors: Qiang Chen , Shouzhi Huang , Dabiao Wang , Tao Li , Weiye Han , Qiang Sun 
Published: October 2017

Abstract
Solid expandable tubular was a field-proven technology in workover operation in China, however its ultimate goal, mono-diameter well, has yet been realized, to achieve this goal, large expansion ratio, enhanced mechanical properties and scientific evaluating method were necessary ingredients.
In this paper we presented the theoretical and experimental study of expandable tubular for well drilling purpose, first it was reported the ABAQUS simulation process of tubular expanded by different ratio, 10%, 20% and 30% respectively, then the relationship of post expanded tubular's properties and expansion ratio was established, the outcome demonstrated that 13% expansion ration brought about the maximum post expanded mechanical strength, reaching N80 casing; second it examined the reliability of expandable thread as it is expanded in the state of being bended at 15°/30m, its structure was redesigned to guarantee 20MPa pressure from outside could be resisted, this paper also introduces the study of residual stress as the tubular was expanded and measures aimed at minimizing it are described.
Field operation was finished in China, the Φ140mm casing well was sidetracked with the maximum dog leg of 11.6°/30m, expandable tubular of Φ108×7mm was delivered into the position and the expansion length was 398m, Φ108mm wellbore size was obtained and all the well tests were up to the standard after operation.
The study offers a new option in the field of well completion, its outcome contributes to the further development of solid expandable tubular.
Value Creation of Digital Oilfield Technology, Study Case Duri Field Well Monitoring
Authors: Achmad Zuam 
Published: October 2017

Abstract
Condition of oil field development become more complex over time. In contrary, profitability of the asset decreases along with production declines. Eventually, the well becomes unprofitable and need to be temporarily or permanently abandoned. By optimizing production costs, the well immediately becomes more profitable and the economic life of the reservoir is extended.
This paper will highlight how i-field, a term that used in internal Chevron for technology application related with Digital Oilfield practices, in which its application in Duri Field operations enables field data to be turned into information, how integrated processes impact decision-making, and lead to actions that ensure production is optimized continously. Due to promising results on this well monitoring application, currently Duri Field operations having initiative to scale up the implementation. This paper will alsodescribe the impact of well monitoring/ digital oil field implementation on reservoir management, production engineering, and in field asset management. As a result of this particular application in Duri Field operations, we will also benchmark between Duri Field actual value creation with publication of CERA regarding Digital Oilfield value potential. Practice of base business process such as integrated operations approach, well reliability and optimization, and business improvement process such as Lean Six Sigma also help in seeking optimization of process workflow systematically.