bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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.
Maximizing the Economic Value of Intelligent Completions through Effective Use of Surveillance
Authors: Gohari Kousha , Gonzalez Luis E , Hosseini Naser , Kazi Saif , Khateeb Ashraf , Awid Abdurrezagh , Jutila Heikki , Kshirsagar Atul 
Published: October 2017

Abstract
Intelligent completions or Smart Well Completions have gained traction in recent years as they provide better control for reservoir management. Simply, intelligent completions consist of the two components, Flow Control and Permanent Downhole Monitoring Systems (PDHMS). While the value of flow control systems has been heavily documented, less has been published regarding the optimization of flow control systems in a proactive manner by more effective utilization of data obtained from the monitoring systems.
This paper simply outlines how monitoring data can be used to optimize flow control systems. By better utilization of the monitoring data active flow control valves are able to be functioned to ensure that the well is operating under optimum conditions. Furthermore monitoring data can be used to validate completion designs while allowing engineers to identify if interventions are required and if so which sections require the intervention.
New Progress of the Offshore Thermal Recovery Technologies in Bohai Bay, China
Authors: Liu Yigang , Han Xiaodong , Zou Jian , Wang Qiuxia , Wang Hongyu , Liu Hao , Jiang Zhaobiao 
Published: October 2017

Abstract
There is abundant heavy oil resource in Bohai Oilfield and good development performance of the pilot area has been acquired by using thermal recovery technology. In recent years, a series of researches and field pilots have been conducted and great progress has been achieved on several aspects.
For HSE, a high-temperature safety control system was developed, which consists of downhole safety valve, cable packer, vent valve, and heat compensator. The overall temperature and pressure resistance value could reach as high as 350°C and 21MPa, respectively. With the development of the high temperature safety control tools and the progress of the high temperature electric submersible pump lifting technique, the integrated tubing with functions of both steam injection and oil production was designed and developed which could be applied for the 250°C cyclic steam and flue gas stimulation. The application of this integrated tubing could greatly decrease production cost by avoiding unwanted well workover.
For treatment of gas channeling, the comprehensive treatment technology which consists of the injection parameters optimization, multi-well cyclic stimulation, and the chemical blocking method was formed based on the experiments, reservoir simulation, and field pilots. Besides, 50t/h steam generator that is suitable for offshore thermal recovery was designed and developed, and the related matching technologies such as nitrogen generation, sea water desalination, artificial lifting, viscosity reduction in wellbore were all studied. The design of the overall development program produced by huff and puff for an unexploited oilfield are carrying out.
Great progress and breakthrough of the offshore thermal recovery technologies in Bohai Oilfield have been achieved in recent years, which will provide powerful technical support for the high efficiency development of the heavy oil resource in Bohai Bay.
A New Practical Approach to Building Tight Reservoir Development Integration Data Model in China
Authors: Liu He , Yan Jianwen , Yao Zixiu , Zhao Zhe 
Published: October 2017

Abstract
The integration data model between geology and engineering is proposed to tackle the key issue of improving average well production by making development plans in a reverse manner and conducting dynamic researches that have foresight, target ability, forecast ability, guidability, pragmaticality, and time effectiveness, accompanied by their instant applications. The model takes 3D geologic models as the core and the unified investigations of geology and reservoir as the foundation, with the complicated relationships and operation difficulties at all development phases considered. All sections are logically combined with each other and are scheduled in a global way where the integration between geology and engineering is taken as the guide, reservoir stimulation as the focus, maximizing production as the target, and factory-like operation as the measure. The fundamental geological and engineering factors that affect the productivity is analyzed, and the adaptivities of well completion and fracturing techniques are systematically assessed with in-depth investigations into the reservoir physical properties, geomechanics, fracture features, well layout and drilling, reservoir stimulation, and liquid discharge for production, et al. Assisted by effective organization, management, and operation practice, rapid accumulation and enrichment of operation experiences and multi-disciplined knowledge covering well drilling and cementation, fracturing, and production and its test production are achieved. Economic development is fulfilled in tight reservoirs by hierarchically and dynamically optimizing engineering efficiency and development profit that arise from continually adjusting and perfecting technical projects related to well drilling, fracturing, and so on.
Design of Jumper Lines to Unlock Potential of Wells - A Success Story
Authors: Siboro M. , Widitya A. , Prabowo A. 
Published: October 2017

Abstract
Total E&P Indonesie (TEPI) has identified several bottlenecks on surface facilities in order to produce higher amount of gas. As TEPI is operating mature fields, existing facilities that were originally designed with higher operating pressure could not accommodate the same amount of gas when operated with lower pressure; Hence the need to perform debottlenecking arises. Most bottlenecks are identified on gathering facilities incoming piping line, designed to connect wells on swamp areas of Mahakam. Previously, base case of production debottlenecking (modification to increase production) requires major effort to completely dismantle existing incoming piping & replacing them with a bigger size piping. This concept will consume a significant amount of production shortfall coming from platform shutdown, equally time consuming procurement lead time and significant material cost. Since 2015, installation of jumper lines has become the base case of production debottlenecking to unlock potential of wells. This modest but robust concept is based on the premise to utilize existing idle flow lines as means to share the flow on the supposedly saturated incoming gathering line. Deterministically, the maximum allowed flow to be handled by the jumper line is determined based on the Flow Induced Vibration (FIV) and also Erosional Velocity criteria. While, some probabilistic approaches in terms of pipe material Likelihood of Failure (LoF) and backpressure analysis has been also considered in the review. Throughout process engineering review & safety due diligence, the main safety concern is the probability of imbalance flow during early operation of the jumper line (possibility of all flow routed to only one flowline and compromising the flowline limitation threshold). However, this potential shortcoming has been managed smoothly by the site operation team (by specific procedure to cover the operation). In terms of shortfall consumption, installation of jumper line option is much appreciated as the shut down for the tie in is limited to the flowline (instead of to the whole platform). Up to end of 2016, there had been 7 jumper lines installed and in operation, giving an additional production of averagely 9 MMscfd per lines, with a cost of ranging between 150,000 200,000 USD. Installation of jumper line has been proven as a reliable debottlenecking means with the highest regard of safety (TEPI core value). This concept is a proof that knowledge of existing installation is of paramount element to optimize the installation. With the very difficult economic environment, desperate times called for desperate measure. It is an excellent demonstration that saving could work both ways: to reduce the expenditure while at the same time gaining more production.
Application of Temperature Surveys to Enhance and Optimize the Limited Entry Hydraulic Fracturing Treatment Design and Placement
Authors: Sidharth P. , Tiwari S. , Ranjan V. , Anand S. , Goyal R. , Vijayvargia U. , Sharma A. , Johri N. , Yadav K. Janardan , Deb D. , Tibbles R. , Pathak S. 
Published: October 2017

Abstract

Objectives/Scope
Raageshwari Deep Gas field located in southern Barmer Basin, in the state of Rajasthan (India), consists of a laminated reservoir where conventional fracturing treatments with a single set of perforations are not economical. In order to improve the project economics, limited entry treatment design (Lagrone, 1963) selected for fracturing. The effectiveness of fluid diversion during limited entry fracture treatment in a laminated reservoir was validated using post injection temperature surveys.

Methods, Procedures, Process
The Limited entry design relies on the pressure drop across the perforations to balance the flow between the various perforation clusters. The treatment design was based on achieving a minimum of 700 psi of perforation friction for adequate diversion between the zones. The perforation friction and number of active perforations was determined using Step Rate/Step Down Tests (SRT/SDT). Post injection temperature surveys were used to confirm fluid entry into the various perforation clusters.

Results, Observations, Conclusions
The following process was applied to more than 90 fracture stages in 15 wells. The fracturing treatments were modeled using log derived mechanical properties and stress contrasts. Diversion into all the clusters was insured by distributing the available perforations based on the predicted fracturing pressure for each zone. Post injection temperature surveys were used to validate the fracturing models. While somewhat qualitative, the post injection surveys did provide valuable insite in some cases, the fracturing simulator predicted fracture growth out of the desired stage area. The post injection temperature survey helped to validate predictions of:
In some cases, post SRT temperature surveys helped justify decisions addition of holes to minimize perforation friction or addition of extra cluster(s) to maximize pay coverage.

Novel/Additive Information
While the use of temperature surveys to estimate fracture height is not new, we believe that this is the most extensive use of temperature surveys in a medium size project incorporating limited entry.
Techno-Economic Evaluation of Carbon Capture Storage Ready for Coal-Based Power Generation in Indonesia
Authors: Sugihardjo Usman , Sismartono Danang , Lubad Aziz M. , Hedriana Oki , Sugiyanto Arief 
Published: October 2017

Abstract
To meet the rapidly growing demand and to provide secure base load power supply, Indonesia's power sector is seeing a growing share of coal in its generation mix. However, increased coal-based generation contributes to increased CO2 emissions. This study aims to define and evaluate the conditions under which coal-based generation could be deemed as carbon capture and storage ready. It considers the technical and economic implications of CO2 capture and storage for two candidate coal power plants in South Sumatera and West Java. A carbon capture storage of a couple of scenarios are evaluated for each power plant based on separation of 90%, 45% and 22.5% of CO2 from the power plant flue gas with an amine scrubbing process, supported by flue gas cleaning processes, and liquefaction of the captured CO2 for transportation to geological storage locations. The carbon capture storage operation would also run for 20 years, 15 years and 10 years, while the power plant design life is 25 years. The potential to sell captured CO2 for enhanced oil recovery in South Sumatera is also assessed. Results of this study will help Indonesia to identify a way to reduce CO2 emissions from the coal-based power sector in the long run and will contribute significantly to putting the country's energy sector on a sustainable development path.
Indonesian Milestone in Production-Sharing Contract in Perspective of Government Take, Contractor Take, Cost Recovery and Production Target
Authors: Daniel Harimurti 
Published: October 2017

Abstract
Recently in Indonesia are experiencing various of revision and improvement in the regulations, related with the oil and gas industry activity, this kind of situation certainly will impact to the investment atmosphere in the Indonesia oil and gas upstream. International Oil Company and the Government has different point of view related to contracts in PSC. Several analysis or study has been done by institutions and individuals through articles or papers on the comparing for the terms and conditions of a contract with different country. But not many have discussed particularly about the general change of PSC in Indonesia.
This study will compare the historical of Indonesia PSC generations from generation I (1966) until the recent fiscal terms of gross split (2017). Those terms will be compare by using a hypothetical block to modelize the PSC block in Indonesia, which consist of several field. Some assumption also will be used for each field with different peak rate, development scenario, capital variable cost ranges, operation variable cost ranges, which those range data are expected still within the range of most likely consist parameter for PSC block in Indonesia.
This study purpose is to analyze if the Gross Split mechanism is more attractive or equal the PSC Cost Recovery. The result of this study shown that the gross split PSC refer to the Minister of Energy and Mineral Resources no.52 year 2017 is still attractive to the investor from the contractor take perspective. Eventough with the PSC Cost Recovery mechanism the contractor feels more secure for the cost that can be recover from the oil and gas that produces, as part of cost recovery. If the application of Gross Split is clear enough from the regulation, tax, assets rent and others, surely this mechanism can attract more investor to do exploration and development in Indonesia.
Regardless of the political and strategic interests of the Indonesia government or the National Oil Company, the results of this study hopefully can be useful for the professional, educational institution, and government for lesson and learn. How the fiscal term can be impact to the government take, contractor take, cost recovery also the production target related with reserves replacement.
A Performance Comparison between Two Novel Multistage Completion Methods in Tight Gas Sandstone Formation from Ordos Basin
Authors: Hao Geng , Tengze Ge , Chuanqing Liu , Xiaojie Yu , Liu Yuan , Wang Weikan , Liu Hai , Niu Li , Yang Baibing , Liu Xiaoli 
Published: October 2017

Abstract
Efficiency, cost, and corresponding well performance are the primary concerns of multistage completions for tight oil and gas development. With the vision of continuous improvement in the industry, novel multistage completion methods such as dissolvable ball seat and sliding sleeve systems become significant technical progressions for multistage completions. Technology comparisons in a specific field help to identify the preferred solution for its reservoir and well construction features, so as to set guidelines for future improvement and planning in similar applications.
Daji field is in the southeastern part of the Ordos basin. Comparing with the central part of the basin, the main formation here has relatively poor reservoir qualities, so it is expected that horizontal wells with multistage completion may help to unlock the production potential via better reservoir contact. Two different completion systems were installed in adjacent wells, one with a dissolvable plug-and-perf system, and the other with a coiled tubing activated sliding sleeve system. The purpose of the project is to evaluate the novel technologies and identify preferred options for future horizontal wells.
Although adjacent, the two candidate wells perform differently during the execution phases. Continuous multistage pumping operations were conducted for both wells, while on-site execution found the dissolvable plug-and-perf system demonstrated much higher efficiency.
Both completion methods are relatively new as multistage stimulation applications. The direct comparison in this field has helped to identify the pros and cons of each system and set up the preference for future development.
Eliminating Underground Blow Out Risk with Constant Bottom Hole Pressure CBHP MPD Technique in Kalimantan Offshore, Indonesia
Authors: Zein Joydi , Iskandar Yoshua , Fadlin Fadlin , Usmar Ray 
Published: October 2017

Abstract
We often face a higher level of difficulty when using conventional methods to drill through a formation with a narrow pressure window. Even slight changes to bottom hole pressure can lead to unwanted non-productive time (NPT) in the process of securing the well, such as handling a loss and/or kick in the wellbore, or even at times, an underground blowout.
Maintaining Constant Bottom Hole Pressure (CBHP) is one of Weatherford's Managed Pressure Drilling (MPD) technologies used to drill safely by keeping the well overbalanced yet below fracture gradient. This is done by applying Surface Back Pressure (SBP) through the use of a Rotating Control Device (RCD) and an Automated MPD Choke Manifold. CBHP applies precise surface back pressure into the annulus by means of automated MPD system to maintain the annulus pressure when circulating and static. CBHP is achieved during pipe connection when the drill string injection is turned off.
In the previously drilled well, the 0.5ppg pressure window caused an underground blowout while in the thief zone. The Synthetic Oil-Based Mud (SOBM) used in this well was designed to be statically under-balanced during pipe connection to keep ECD within the 220psi window while dynamic and static. The slip joint packer - the weakest link in the annulus system - restricted the MPD SBP to maximum of 350 psi after considering the margin of error. Due to high wellbore friction pressure, the Pressure-While-Drilling (PWD) signal was intentionally turned off 60 meters before Total Depth (TD) was called by reducing the pump speed from 430gpm to 300gpm.
MPD CBHP technique was successfully applied to drill the well until target depth was achieved exceeding the poor performance in the previously drilled well where target depth was not achieved and the well was abandoned due to underground blowout.
This paper describes achieving CBHP with Managed Pressure Drilling technique and the use of an automated system which enables "walk-the-line" between pore and fracture pressure gradient. As a result, the exploration well that was considered "undrillable" with conventional drilling technique in East Kalimantan area was successfully drilled to TD. The ability to precisely control the annulus pressure with statically underbalanced mud is one of distinct advantage of MPD which allow operators to reach planned target depth and retrieve subsurface information through logging operations.