bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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>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

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

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.
Maximizing More Barrels in Brownfield Rejuvenation through Integrated Collaboration
Authors: Mohd Sharir N. A. , Mohamad Nordin N. F. , Abdul Latif A. H. , Wan Khairul W. M. , Mohamed T. A. , Johar Z.
Published: October 2017

In today's business paradigm, early monetization of resources is a key competitive edge. This requires an effective development plan fostered via sound cost-benefit analysis followed by the systematic and timely implementation of said plan. The drive to obtain faster oil has led to a comprehensive collaboration between PETRONAS and PSC Contractors in one of its biggest oil fields.

Daisy Field is situated 170km off the coast of Terengganu, Malaysia and the first oil was discovered in 1991. The field reached its peak production in 1999 (90,000 bopd) and has undergone steep decline since then, with current average production of ~25,000 bopd. Using extensive historical surveillance and production data, an initiative was taken to identify and unlock remaining reserves.

A new approach to an existing engineering technique called Locating the Remaining Oil (LTRO) has been applied in Daisy Field as an alternative to time consuming static-dynamic modelling. This new approach integrates cased hole log information, production data and decline curve analysis in order to identify bypassed or undrained oil that can be monetized through behind casing or infill drilling.

This paper is a case study on the utilisation of LTRO for brownfield rejuvenation. LTRO is a low-cost but effective solution for idle well reactivation;it may accelerate identification of opportunities, which could be exploitable even during low oil prices, as prevailing currently. Following its deployment within the collaboration, reserves addition has been realized, value created and the cycle time for brown field development plan approval was reduced significantly. This paper will also demonstrate how integrated collaboration between host government, operator and service provider can be a good synergy for effective brownfield rejuvenation.
Drilling Problems Mitigation in Geothermal Environment, Case Studies of Stuck Pipe and Lost Circulation
Authors: Nugroho W. A. , Hermawan S. , Lazuardi B. H. , Mirza R.
Published: October 2017

Geothermal energy is one of fast growing renewables resource in the world. Demand for renewable resources leads to increase of geothermal drilling activities. Well cost contributes up to 40 % of total geothermal project cost. Drilling in geothermal faced many challenges due to its natural characteristics. The most common problems are lost circulation and pipe stuck. Highly fractured zone is the ideal spot for geothermal production. Lost circulation is common in highly fractured formation. Stuck pipe is another problem. Stuck pipe can lead to extra cost of lost-in-hole and fishing operation. Water played an important role in geothermal drilling, not only to keep the wellbore pressure but also to cool down the temperature.

This paper shows some severe cases of lost circulation and pipe stuck in geothermal drilling. All of the data are taken from geothermal drilling projects in Indonesia. The cases of lost circulation can be divided into two major type based on the location, shallow and deep lost circulation. Each has different technique to overcome lost circulation. Two cases in pipe stuck presented in this paper are the most severe incidents in geothermal project in Indonesia. Underbalanced drilling was a common application in highly fractured and subnormal pressured formation as found in geothermal. Both cases performed underbalanced drilling prior to stuck pipe incident. This paper evaluates gas-liquid flow rate based on Guo and Ghalambor (2002) criterion.
Evaluation of Factors Influencing the Effectiveness of Passive and Autonomous Inflow Control Devices
Authors: James E. J. , Hossain M. M.
Published: October 2017

Autonomous Inflow Control Devices (AICDs) are a relatively new technology with the potential to improve the production performance of horizontal wells. The devices control the inflow of reservoir fluid to equalise influx along the length of a horizontal well, and adjust the level of constraint depending on the fluid flowing such that water production is hindered and oil production is promoted. In order to assess the effectiveness of autonomous ICDs compared to passive ICDs, which apply a constant level of restriction, numerical simulations and sensitivity studies were conducted.

A detailed model of the lower completion of a theoretical horizontal well was constructed using an Integrated Production Modelling (IPM) simulator. ICDs were represented using an Inline Programmable Element and equations to calculate the pressure drop of a range of different passive and autonomous ICDs were input. Simulations run on this model allowed the pressure drop across each ICD to be analysed, and the liquid rates at the heel and toe of the well to be compared, to assess how effective the ICDs are in promoting a balanced influx from the reservoir along the entire horizontal length of the well. Oil viscosity, heterogeneous permeability, and oil-water-contact levels were then varied to evaluate the behaviour of the ICDs in different scenarios.

Analysis of the simulation results suggests that none of the tested ICDs are the best performers in every scenario. The Rate Controlled Production (RCP) Valve AICD is the most effective device in heavy oil wells and in wells with uneven oil-water-contacts. The EquiFlow AICD is the optimum performing devicein a reservoir with heterogeneous permeability, and the nozzle ICD is the most effective device in light oil wells. Comparative study of the behaviour of passive vs autonomous ICDs indicates that there is a difference in performance between these two types of ICDs. In some cases autonomous ICDs can provide significant benefits, where as in others the passive ICDs are just as effective.
Successful Application of Expandable Liner Hanger in HT Sidetracking Well Completion: A Case Study in Liaohe Oilfield, China
Authors: Huang Shouzhi , Chen Qiang , Han Weiye , Li Tao , Ming Eryang , Sun Qiang
Published: October 2017

There are a number of challenges existing in conventional slip-type liner hanger, such as undersealing annular of overlapping liner, limited high temperature resistant performance, et al. With the development and improvement of expandable tubular technology, expandable liner hanger (ELH) is developed to replace the current hanger and external packer completely, aiming at the shortcomings of the conventional liner hanger. ELH can isolate packer liner and the main casing, replace the conventional cement sealing way, and reduce the overlap length.

Here a new thermostable ELH was developed to apply in HT sidetracking well completion. The length of annular seal section of ELH is short but reliable, and maximum sealing pressure reaches 35 MPa. According to the requirements of the drilling process, tool string can be lifted, lowered, rotated and circulated to ensure extension liner string down to the bottom and improve the quality of liner cementing. The construction process is simple with low pressure, reliable operation and long service life after the production. The ELH has large bore size, larger than conventional casing under the hanger, in order to run in oil pump through the extension liner string. So the running in depth of pump is not affected by hanger diameter that can improve oil recovery ratio. The metal sealing is used in ELH for heavy oil thermal recovery wells, and it can be used under highest temperature of 300 C. This ELH tool string can fulfill tool setting and bottom sub salvage at one trip. The annular seal pressure of ELH is more than 35 MPa, construction pressure is 25 to 35 MPa, and suspension force is 600 kN.

This new ELH technology has been applied in HT sidetracking well completion in Liaohe oilfield. The hanger position is from 1491 m to 1493 m, inclination is 89 degree, the length of overlapping section in casing is 33 m, the length of sieve tube is 204 m, the length of blank casing is 55 m, and total length is 259 m. The running in depth of sieve tube guide shoe is 1753 m. Lift string suspending weight is 32 tons. ELH suspension was successful.

This paper provides a solution to HT sidetracking well completion using thermostable ELH technology. And the experience of operation process was shared in this case to be helpful for technology applications in similar situations.
Transient Thermal Model of Drilling Fluid in Wellbore under the Effect of Permafrost Thaw during Drilling in Arctic Region
Authors: Xuerui Wang , Baojiang Sun , Zhiyuan Wang , Yang Zhao , Jintang Wang , Zhennan Zhang , Gao Yonghai
Published: October 2017

The arctic could hold about 30% of the world's undiscovered gas and 13% of the world's undiscovered oil according to an assessment by the United States Geological Survey (USGS). While, arctic oil and gas exploration is faced with various challenges such as the extremely cold polar environment, the ice scour, the permafrost. Permafrost is the perennially freezing soil (actually freezing pore water), and it can be an important geologic hazard and constraint. Permafrost is very common in arctic region, about one-half of the total land area of Canada and Russia and 85% of Alaska is underlain by permafrost. Besides, sub-bottom permafrost is also wide spread phenomenon of Arctic offshore areas.

At present, the traditional thermal models of wellbore use an algebraic approximation to describe the heat transfer between wellbore and formation. Thus a new model should be established considering the effect of permafrost thaw during drilling in arctic region. As a matter of fact, the phase change of ice in permafrost needs to absorb heat from wellbore which can have an effect on the wellbore temperature. At the same time, migration of water from warm to cold regions will happen during the process of the thaw of permafrost. The migration of water will have an effect on the temperature due to the heat transfer along with the water. In addition, temperature in wellbore can be negative after long shut-in time due to the extremely cold polar environment which could lead to the blocking of wellbore.

In this paper, a transient thermal model of wellbore during arctic drilling is established considering the effect of permafrost thaw in this paper. On the basis of the new model, a simulation of an arctic well is made and some conclusion are made from the case study: The temperature fields in wellbore and permafrost interact with each other. Besides, the temperature in wellbore drops to negative due to the extremely cold environment after long shut-in time, and the drilling fluid in wellbore could be frozen consequently. Long shut-in time should be avoided during drilling in arctic region.

The new model established in this paper can determine more reasonably the wellbore temperature in artic permafrost region than the traditional model. A method to determine the reasonable shut-in time is given in this paper which can provide safety guidance during drilling in arctic permafrost region.
Integrated Portfolio Analysis of Gas Field Clusters: How to Make Fast, Yet Informed Decisions
Authors: Kumar Gyanendra , Bezemer Taco Den , Chima Chima , Dewil Stoffel , Trivedi Bhaskar
Published: October 2017

Key project decisions like field sequencing, plateau size, and design back pressures in a green gas field cluster development require a robust integrated system modelling. Given that most project decisions are made in economics domain, it is crucial to include the project economics within the integrated system modelling suite. This paper describes application of a workflow which integrates the subsurface, surface, costing and economics evaluation within the ambit of a single integrated modelling tool.

Typically network models are computationally intensive and project teams will only run them for few deterministic cases. The probabilistic analysis is performed at reservoir/field level, and they are combined to define deterministic (Low, Mid, High) case network models. However, this approach poorly captures surface-subsurface interactions and doesn't provide full solution space at the network level. Furthermore, to generate development options and scenarios, typically oversimplistic subsurface models are used that do not sufficiently capture liquid yield over time and water encroachment.

The proposed workflow does probabilistic simulations at network level to capture the full solution space. The workflow allows representation of project decisions and uncertainties under the same platform. Furthermore, representative modelling of reservoir architecture and fluid fractional flow allows more accurate prediction of liquid hydrocarbon and water which helps in robust facility design. Semi-automated nature of the toolkit allows generation of project economics for large number of sensitivities and scenarios in quick time. This approach is very useful where with only basic information fast analysis is required to start commercial negotiations, and in situations where good statistical coverage is more important than very detailed outcomes (even when detailed information is available) to support decsions.
Managing Offshore Oil Field to Enhance Ultimate Recovery in Asri Basin, Southeast Sumatera, Indonesia
Authors: Waskito L. B. , Widiatmo R. , Afi F. N.
Published: October 2017

This paper covered success collaboration between sub-surface and surface engineer in managing mature offshore oil field in Asri basin, Southeast Sumatera, Indonesia. The main objective was to maintain oil production rate and increase ultimate recovery in the most efficient way, technologies that applied strictly selective to minimize risk while optimize oil production. Common problem faced are extremely high water cut and high operating cost due to massive artificial lift application.

The three effective tailored methods in this paper are: (1) Determining residual oil volume and locating the position. Material balanced calculation and core analysis are the tools to determining residual oil volume, while tracer test conducted in order to determine the location and distribution of the oil remained. (2) Surface facilities assessment, facilities are ageing and need to refurbished/replaced after 27 years of production, it creates limitation in operation area. (3) Potency screening, in this phase we focused more on technical difficulties assessment, both sub-surface and surface (from method 1 and 2) result analysis are combined to determined technology selection. After that we put into action, and do evaluation on cost spending and production performance.

Efficiency is the key issue in mature field redevelopment, solid collaboration between sub-surface and surface team lead to satisfying result to reduce production decline. Several case studies have been included in the paper to highlight the detail project: (1) Idle wells, to increase production it is very important to increase well count, the wise way is by utilize existing wells in idle condition. Mechanical failure, water out, formation damage, low potential, etc. are cause of idle wells, in the last 3 years 13 wells successfully back to production. (2) Modified completion fluid, one of technology applications with ‘breakthrough’ result. In depletion drive reservoir we found lot of residual oil potency that can't be sweep, the solution is to reduce oil viscosity around wellbore and increase the mobility using modified completion fluid, and the result is beyond expectation. (3) Water injection redirection, based on performance evaluation and tracer injection analysis, several injectors is ineffective due to reservoir connectivity and mechanical issue, this project creates new sweep pattern and successfully increase recovery factor. (4) Mechanical loss handling, we found big losses contribution from tubing leak, after laboratory and field analysis losses can be reduced.

Technology and integration of sub-surface and surface capabilities are vital to unlocking the full potential of mature assets and achieving higher recovery factors. Application of the three tailored methods was considered as an appropriate way to approach and manage a complex mature field redevelopment.
Oilfield Microbiology: Effective Evaluation of Biocide Chemicals
Authors: Bennet Douglas
Published: October 2017

"Kills 99.9% of bacteria". Sounds impressive. Consumers will have seen this claim on supermarket shelves on all kinds of household biocide chemicals such as hand soaps and detergents. In reality, what does this actually mean? Is a kill target of 99.9% an effective biocide? On the face of it, it sounds very good. However, when referring to microbiological populations, like bacteria, this requires context. What was the original number that was reduced by 99.9%? When quantifying microbiological populations, it is common to use extremely large numbers, referenced in logarithms (1.0 × 105 or 1.0 × 106 cells).

Reducing bacterial populations by 100% using batch dosed biocide chemicals is an impossible feat. It will never be possible to entirely eliminate 100% of bacterial populations, as some will always survive and potentially recover to pre-dose populations. Therefore, selection of the most efficient biocide chemical is of the utmost importance.

In the example scenario of a hand soap, the target of 99.9% is very difficult to achieve. The biocide chemical is applied to the target surface area (hand) and almost immediately diluted and washed off by a running stream of water. The chemical might get a contact time of up to 1 minute to kill 99.9% of bacteria under normal circumstances.

Although hand soap is not directly related to control of bacterial populations in oilfield process systems, the theories behind the testing of all biocide chemicals are the same. It boils down to three parameters that need to be tested; chemical, concentration and contact time, tested against microbiological populations. The questions any operator should ask before using a biocide chemical should be; Which biocide chemical?What concentration should be applied?How long should the biocide chemical be added for?

By answering these questions, the operator will have learned key points as to the efficiency of the biocide chemicals under test in relation to the required conditions.

This paper will discuss a recent example of a biocide chemical evaluation carried out by a Malaysian operator, in which fourteen different biocide chemicals were tested to determine the most efficient biocide chemical. Each biocide chemical was tested under controlled laboratory conditions against both planktonic and sessile mixed microbial consortia populations, and ranked for efficacy.
Field Test Results in Malaysia Wells of a New-Generation Slim Pulsed Neutron Logging Tool
Authors: Millot P. , Wong F. K. , Rose D. A. , Zhou T. , Grover R. , Sundaralingam S. , Amin F. , Prasodjo A. , Johare Dzulfadly , Kwang Hui Nicholas Foo
Published: October 2017

Pulsed neutron spectroscopy (PNS) is a well-established technology for characterizing reservoir saturation through cased hole, using either sigma (Σ) or carbon/oxygen (C/O) ratio measurements. However, the current technologies struggle to deliver reliable answers in complex completions. Tubing and casing, with varying tubing and annulus fluids, or dual tubing completions with changing annulus and tubing fluids represent cases in which it becomes difficult to identify fluid contacts in the formation and calculate remaining saturations.

A new-generation slim pulsed neutron logging tool has been developed to deliver reliable answers in conditions that challenged existing technologies. It introduces the new petrophysical measurement, fast neutron crosssection. This measurement is highly sensitive to variations in gas volume and insensitive to variations in water volume, independent of neutron porosity and formation Σ properties. It provides high-resolution spectroscopy with a much-improved accuracy and precision of all elements measured, including the key element for oil saturation, carbon. The carbon measurement is used conventionally for C/O, and it is used directly to derive total organic carbon (TOC), which is then converted to oil saturation.

This tool delivers the self-compensated Σ and neutron porosity measurements in a wide range of conditions, including complex completions and varying amount of gas in the wellbore or annulus.

The field test results in this paper demonstrate the performance of this new tool in a few wells from Malaysia. All present some complex completions, from single tubing inside 7-in. casing and 8.5-in. hole to dual 3.5-in. tubing in 95/8-in. casing and 12 ¼-in. hole. Additional challenges include gas-filled annulus, multizone completion with sliding side doors (SSD) and wire-wrapped screens (WWS), and environments in which there are no water sands for C/O measurement calibration.

The logging objectives include determining theoil/water contact (OWC) and the gas/water contact (GWC),quantifying the current saturation, confirming the source of water for water shutoff determination and anticipated gain, and verifying sand-filled annulus. A back-to-back comparison with the previous technology was also run in the first well, allowing a directcomparison of the measurements from the new and the existing tools in the same conditions.
A Case Study of Shallow Water Flexible Pipe Project Execution for Maintaining Production in Marginal Field, Offshore North West Java Indonesia
Authors: Sinulingga E , Yananto H
Published: October 2017

An offshore well-platform namely "xyz" is in a marginal gas field operated by Pertamina Hulu Energi Offshore North West Java (PHE ONWJ). "xyz" production is transported to the "xy" platform via a 6.3 km 8" Main Gas Line (MGL), which has been in operation since 2002. In 2015 several leaks were detected and it was known that well ‘xyz-1’ produced high CO2. A Repair by conventional means i.e. replacement with the same steel material was deemed uneconomic due to the high CO2 content. A study was therefore initiated to evaluate the technical and economic feasibility of low capital cost and low maintenance cost technologies to rehabilitate pipelines in marginal fields with high CO2 content without increasing safety or environmental risks.

In the appraisal stage, several technology options were considered and a thermoplastic pipe was selected as the preferred alternative compared to traditional rigid carbon steel pipeline. The assessment process started with a pipeline technology review, followed by technical compatibility/acceptance study, a check of commercially available pipe sizes and a comparison of total installation cost, installation schedule, and operation-maintenance considerations. The decision was facilitated by Expected Value Decision Analysis. The expected value of each option included CAPEX, OPEX, NPV, and all quantified aspects and risk.

The thermoplastic plastic pipe assessed is a flexible pipe for shallow water consisting of polyethylene (PE) internal liner, annular ring steel strip armor, and PE outer sheet. The PE inner liner is nearly hermetic, but allows traces of gases such as CH4, CO2, H2S, and H2O to permeate through. These permeants tend to accumulate in the flexible pipe annulus. A slight overpressure above atmospheric develops in the pipe annulus driving the gases to the end fittings where they are vented, preventing excessive pressure build up.

Additional weight is required for on bottom stability of thermoplastic pipe to be laid in Offshore North-West Java area. The installation spread was using the available Pipe Lay Barge blanket contract for the Pipeline Repair and Replacement Program. Even though different technical approach needed to accomplish the work, such as the need of additional weight and using lay barge instead of DP2, the selected concept is still the most economic compared to other options. The CAPEX spending was competitive compared to carbon steel pipe one. In addition, OPEX reductions can be achieved by reducing pigging operations and eliminating In-line Inspection (ILI) and chemical injection.
A Study of Methane Foam in Reservoir Rocks for Mobility Control at High Temperature with Varied Permeabilities: Experiment and Simulation
Authors: Kamarul Bahrim R. Z. , Zeng Y. , Vincent Bonnieu S. , Groenenboom J. , Mohd Shafian S. R. , Abdul Manap A. A , Tewari R. D. , Biswal S. L.
Published: October 2017

Reservoir heterogeneity and permeability contrast are some of the factors that affect the efficiency of EOR applications in the field. The main issues of current secondary and tertiary recovery methods such as water, gas, or water-alternating-gas (WAG) injections in the field are poor mobility control, gravity segregation, and viscous fingering, among others. Displacement conformance needs to be improved as to ensure that target regions are properly swept. To address these issues, foam has been proposed to complement the existing EOR applications, with the target to improve overall sweep efficiency through the reduction of gas mobility. However, very limited data of this effect are available on the actual reservoir rocks under field conditions. In this paper, laboratory research work was conducted to capture the effect of heterogeneity on foam using actual reservoir rocks of varied permeabilities. It is observed that foam is more stable in high permeability cores compared to low permeability cores. Our finding in actual reservoir rocks is consistent with the literature observations conducted in outcrop core samples. Moreover, we used a texture-implicit-local-equilibrium model to parameterize our foam system. Mobility reduction of the gas phase by foam was found to be selectively higher in cores of higher permeabilities. Another finding from the model is that, in all cases, the parameter epcap, which regulates the significance of shear-dependent rheological behavior, approximately equals to 1. Foam exhibit Bingham-like fluid properties where pressure gradient is irrelevant to the shear rates. We also simulated our foam system in a hypothetical two-layered model reservoir using MoReS. We systematically compared the oil displacement by water-alternating-gas (WAG, no foam) process and by surfactant-alternating-gas (foam) process. It is concluded that foam can effectively improve the conformance of the oil displacement in presence of reservoir heterogeneity. The permeability-dependent foam rheology can divert the displacing fluids from the high-permeability region to the low-permeability region and therefore enhancing the overall oil recovery efficiency.
Study on the Application of Whole Process Monitoring and Control Technology for Separated Layer Water Injection to Block
Authors: Jia Deli , Pei Xiaohan , Zhu Zhenkun , Zhu Shaogong , Liu Chongjiang , Guo Tong
Published: October 2017

Oilfield development in China has entered the high water cut stage. Waterflooding development is faced with ineffective water injection and rapid increase of water cut, due to complex injection-production relationship, unbalanced production and severe interlayer contradictions. Besides, total number of separated layer injectors increases with years, single-well layers subdivision becomes more elaborate, and the measuring and adjusting frequency is gradually accelerated, which exponentially increases measuring and adjusting workload. A low cost whole process monitoring and control technology package for separated layer water injection was developed in this paper to tackle key problems about single-layer downhole flowrate measurement, layered adjustment and communication in wellbore, and to realize the digitalized real-time monitoring of separated layer pressure and injection rate for single well and the networking of dynamic water injection monitoring information on blocks and reservoirs. This technology was piloted in block. The pilot test block has small well spacing and fast breakthrough speed of injected water, where oil to be produced has greatly varied physical properties, and the production in different layers is unbalanced. In recent years, the water cut has increased fast, the annual water cut increase is above 0.8%, and the comprehensive water cut is 97.2%. By utilizing real-time monitoring and adjustment, effective water injection has been realized, and the increase of water cut has been maintained at less than 0.5% since one year ago when the block was selected for pilot test. Moreover, this technology is also provided with the functions of on-line seal check, static pressure test, water injection profile test and dynamic adjustment, and so site test and adjustment jobs can be minimized.