bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Surveillance and AI based Steam Allocation Optimization Workflow for Mature Brownfield Steam Floods
Authors: Kumar Anjani , Novlesky Alex , Bityutsky Erykah , Koci Paul , Wightman Jeff 
Published: December 2018

Abstract
Heavy oil reservoirs often require thermal enhanced oil recovery (EOR) processes to improve the mobility of the highly viscous oil. When working with steam flooding operations, finding the optimal steam injection rates is very important given the high cost of steam generation and the current low oil price environment. Steam injection and allocation then becomes an exercise of optimizing cost, improving productivity and net present value (NPV). As the field matures, producers are faced with declining oil rates and increasing steam oil ratios (SOR). Operators must work to reduce injection rates on declining groups of wells to maintain a low SOR and free up capacity for newer, more productive groups of wells. Operators also need a strong surveillance program to monitor field operational parameters like SOR, remaining Oil-in-Place (OIP) distribution in the reservoir, steam breakthrough in the producers, temperature surveys in observation wells etc. Using the surveillance data in conjunction with reservoir simulation, operators must determine a go-forward operating strategy for the steam injection process.
The proposed steam flood optimization workflow incorporates field surveillance data and numerical simulation, driven by machine learning and AI enabled Algorithms, to predict future steam flood reservoir performance and maximize NPV for the reservoir. The process intelligently determines an optimal current field level and well level injection rates, how long to inject at that rate, how fast to reduce rates on mature wells so that it can be reallocated to newly developed regions of the field. A case study has been performed on a subsection of a Middle Eastern reservoir containing eight vertical injectors and four sets of horizontal producers with laterals landed in multiple reservoir zones. Following just the steam reallocation optimization process, NPV for the section improved by 42.4% with corresponding decrease in cumulative SOR by 24%. However, if workover and alternate wellbore design is considered in the optimization process, the NPV for the section has the potential to be improved by 94.7% with a corresponding decrease in cumulative SOR by 32%. This workflow can be extended and applied to a full field steam injection project.
Land Controlled Source Electromagnetic Technique for Shallow Viscous Oil Reservoir Characterization of North Kuwait
Authors: Kumar Rajive , Biao Ren Zu , Khalid Ahmad 
Published: December 2018

Abstract
Controlled Source Electromagnetic (CSEM) method provides an effective imaging tool for the reservoirs characterized by distinctive resistivity signature, such as lithological change or fluid saturated channels. Acquisition, processing and modeling of CSEM data provide us an effective complementary information to seismic in characterization and potentially production of viscous oil from the shallow reservoir. CSEM methods using electric dipole sources are very sensitive to thin resistive layers similar to shallow clastic reservoir of North Kuwait. Prior to CSEM survey, the sensitivity of this method to presence of viscous oil bearing layers was tested through synthetic simulation study utilizing several well logs of shallow clastic reservoir. Feasibility study highlighted the good sensitivity of CSEM to resistive shallow clastic reservoir.
In CSEM survey layout, the source position started with offset from the receiver spread progressing through the spread and move to the opposite side by same offset. The electric field data are recorded on 100m dipoles, at continuous 100m interval, with 100m between receiver lines. Transmitter dipoles were also 100m, but spaced at 300m intervals along line. Data processing is carried out in the frequency domain. Source and receiver calibration functions are included in the process along with all geometry data. Amplitude and phase response is obtained for each source and receiver combination at multiple frequencies. Measured amplitude and phase values varied depending on the source-receiver separation and more importantly on the subsurface resistivity distribution between source and receiver.
The CSEM synthetic responses obtained through forward modeling are compared with observed processed data to perform a further quality control step and start a qualitative data imaging. In fact, the measured electric field amplitude and phase deviate from the synthetic data as much as true subsurface resistivity distribution deviates from reference model. Another essential step in CSEM data analysis consists of inverting the data to infer a resistivity model that could fit the observed measured data. We followed an incrementally more complex workflow from 1D CSEM laterally constrained anisotropic inversions to 3D anisotropic CSEM inversion. 3D inversion of co-located MT data and 1D CSEM inversion helped to build a reliable a priori model.
The output anisotropic resistivity earth model showed good consistency with the previous step qualitative imaging results and with the available resistivity logs. Resistivity volume obtained from 3D CSEM inversion can be interpreted to correlated resistivity lateral variation in depth and space with known features to infer rock physics variations at the shallow reservoir levels. This information, together with the results of non-seismic data acquired at the same time and of the seismic dataset has helped in characterizing the shallow clastic viscous oil reservoir.
Cost-Effective Improvement of Core Analysis for Heavy Oil Development in Northern Kuwait
Authors: Ahmed Khalid , Tyagi Aditya , Saikia Pabitra , Taqi Fatma , Al-Rabah Abdullah , Appel Matthias , Benham Philip , Zhang Ian , Mani George , Luague Jefferson 
Published: December 2018

Abstract
Routine and Special Core analysis (RCAL and SCAL) are the cornerstone of Petrophysics Modeling and Formation Evaluation. In order to obtain the required information, it is important to have quality core, its processing and analysis. This paper summarizes current practices vis-à-vis improvements made in key technical areas.
Coring and core analysis are cost-intensive processes. Only quality data from representative core plugs can offset the high cost and can help to achieve the objectives of coring and core analysis. To obtain consistent quality core plugs, coring practice, on-site handling and plugging procedure have to be the best in class. Coring and core analysis in the shallow-depth Heavy Oil Fields in Northern Kuwait have been in place for some time. The processes like i) coring operation ii) on-site core handling and preservation iii) core slabbing iv) core plugging and finally v) core analysis are continually improved.
In order to be efficient and cost-effective, all the above processes were re-visited, quality gaps identified and improvements implemented by incorporating unconsolidated formation characterization from the available extensive petrographic studies. For example in the coring practice front, coring and core handling protocols were modified for sour heavy oil-bearing formations noticed in parts of the fields. On-site dry ice was used in addition to the prevalent practice of normal freezing. In the laboratory analysis front, obtaining representative plugs and getting useful results from them were the key challenges. Compared to the previous practice of liquid N2 injection from top only during core slabbing by band saw, liquid N2 injection from both top and bottom resulted in improved core integrity. The previous practice of plunge cutting of plugs with liquid N2 was continued. Before any analysis, Computer Tomography (CT) scan of the plugs was performed to discriminate plug-integrity related issues.
This paper discusses lessons learnt from past coring and core analysis processes and their impact on heavy oil development. Improvements to these processes as cost-effective measures are presented through real examples. Recommendations for improvement include field procedure, laboratory process, and usability of the tests performed, which may be useful to the industry where heavy oil core analysis is used.
Miscible Gases Based EOR in Unconventional Liquids Rich Reservoirs: What We Can Learn
Authors: Alfarge Dheiaa , Alsaba Mortadha , Wei Mingzhen , Bai Baojun 
Published: December 2018

Abstract
Over the last decade, Unconventional Liquids Rich Reservoirs (ULR) have become the main target for oil and gas investors as conventional formations started to deplete and diminish in numbers. These unconventional plays have a huge oil reserve; however, the primary oil recovery factor is predicted to be less than 10%. Unconventional Improved Oil Recovery (UIOR) techniques are still a new concept in the oil industry since there is no commercial project reported for any IOR technique yet. Miscible gas based EOR technique might be the most potential strategy to improve oil recovery in such complex plays.
In this study, a comprehensive and critical review has been conducted to evaluate the feasibility of miscible gas based EOR technique in ULR. The reports and studies from three different approaches (lab, simulation and pilot tests) were summarized and combined to provide in-depth insights and lessons learned from the applicability of miscible gas based EOR in ULR. Firstly, the main problems in the previous lab and simulation approaches, which were used to investigate the viability of different EOR methods, have been diagnosed. Secondly, the performance of injecting different miscible gases to enhance oil recovery in the pilot tests conducted in ULR has been extensively discussed. Thirdly, the physical and chemical reasoning behind the performance gap for the injected gases in the lab scale versus the field scale of ULR been diagnosed.
This study reported that most of the previous lab and simulation approaches suffered from significant lacks and drawbacks, which created a clear gap in the performance of the injected gases in the lab scale versus the field scale. This research clearly found that the performance of Natural Gas (NG) injection is significantly better than the performance of CO2 injection in terms of enhancing oil recovery in the field pilots. This study also found that the production response of unconventional reservoirs to the injected NGs is much faster than that for the injected CO2. Combining the pilot tests data and simulation studies showed that the number of cycles in huff-n-puff operations has a negative impact on CO2-EOR while it has a positive impact on NGs-EOR. Finally, this research provided deep insights on what the operators can expect from the EOR performance by injecting different miscible gases in the lab scale versus the field scale of ULR.
Advanced Ion Management to Improve Oil Recovery in Oil-Wet Carbonate-Sandstone Composite Reservoirs
Authors: Alhuraishawy Ali K. , Bai Baojun , Wei Mingzhen , Al-Bazzaz Waleed H. 
Published: December 2018

Abstract
Waterflooding with different inonic composition called advanced ion management which play a role with ionic composition of injected water to enhance the oil production. In the last decate, many studies pointed out that the composition of injected water could changes rock wettability during waterflooding. The main purpose of this study is to evaluate the effects of SO4 and low salinity water on improving oil recovery in oil-wet carbonate reservoirs. Sulfate ion concentration, low salinity water, rock composition, porosity, and permeability were examined using a designed model. Typical seawater, increase SO4, two and three times in the seawater, and low salinity water that had been diluted 10 and 100 times were applied as waterflooding processes with three different average matrix permeability. Oil recovery factor improved as sulfate ion concentration increased and water salinity decreased by changing core wettability with greater water-wet conditions. Morover, the diluted seawater has more effect than sulfate ion concentration when a carbonate core has a few percentage of silica. Sulfate ion concentration performance increased with porosity and temperature, and the dilute seawater showed more effect at high temperature. Increased sulfate ion concentration followed by diluted sea water with present silica in the core composition might be a viable technique to improve oil recovery in the carbonate reservoir. The experimental results validated by field-scale simulation study and provides deep insight into understanding of advanced ion management performance.
Technical and Economical Aspects of Use of Solar Energy in Oil & Gas Industry in the Middle East
Authors: Temizel Cenk , Irani Mazda , Canbaz Celal Hakan , Palabiyik Yildiray , Moreno Raul , Balikcioglu Aysegul , Diaz Jose M. , Zhang Guodong , Wang Jie , Alkouh Ahmad 
Published: December 2018

Abstract
As major oil and gas companies have been investing in renewable energy, solar energy has been part of the oil and gas industry in the last decade. Originally, solar energy was seen as a competing form of energy source as a threat that may replace or decrease the share of fossil fuels as an alternative energy resource in the world. However, oil and gas industry has adapted to the wind of change and has started investing and utilizing the solar energy significantly. In this perspective, this study investigates and outlines the latest advances, technologies, potential of solar both as an alternative and a complementary source of energy in the Middle East in the current supply and demand dynamics of oil and gas resources.
A comprehensive literature review focusing on the recent developments and findings in the solar technology along with the availability and locations are outlined and discussed under the current dynamics of the oil and gas market and resources. Literature review includes a broad spectrum that spans from technical petroleum literature with very comprehensive research to non-technical but renowned resources including journals and other publications including raw data as well as forecasts and opinions of respected experts. The raw data and expert opinions are organized, summarized and outlined in a temporal way within its category for the respective energy source.
Solar energy is discussed from a perspective of their roles either as a competing or a complementary source to oil and gas. In this sense, this study goes beyond only providing raw data or facts about the energy resources but also a thorough publication that provides the oil and gas industry professional with a clear image of the past, present and the expected near future of the oil and gas industry as it stands with respect to renewable energy resources.
Among the few existing studies that shed light on the current status of the oil and gas industry facing the development of the renewable energy are up-to-date and the existing studies within SPE domain focus on facts only lacking the interrelationship between solar energy and oil and gas such as solar energy used in oil and gas fields as a complementary green energy.
Concentric Coiled Tubing Technology for Well Cleaning & Evaluation in Shallow Horizontal Wells: A Case Study from Heavy Oil Field Kuwait
Authors: Kommaraju Srinivas Rao , Garcia Jose Gregorio , Al-Bahri Abrar Marwan , Al-Faudari Mohammad J , Al-Naqi Ahmad Mohamad 
Published: December 2018

Abstract
The drilling of shallow horizontal wells in unconsolidated sand formations faces the particular challenge of achieving proper well trajectory, needed that minimizes dog leg severity and if not accomplished can increase well intervention frequency. These well complexity challenges may result in improper wellbore sand clean outs that can promote early failure of the artificial lift equipment and increase the frequency of interventions that cause production deferment. Wellbore clean out operations are risky because of potential fluid losses and low reservoir fracture pressures, which limit downhole clean-out circulating pressures.
Concentric Coiled Tubing (CCT) technology has been used to clean out horizontal slotted liner sections with suspected sand fill. This sand fill reduces well productivity due to sand bridging within the slotted liner. The application of CCT technology reduces the risk of lost or limited fluid returns and provides an effective clean out method. In addition, it can also provide drawdown at the CCT power head, resulting in lost workover fluids from the wellbore effectively removed by using the system under vacuum-mode. The multiple operating system modes provide the benefit of cleaning and treating the wellbore in the same run.
Workover interventions using conventional CT have been used in the past with limited success. Moreover, in some cases, these wells have showed sharp production declines after post CT clean-out operations. It was suspected that in addition to sand fill issues, formation damage has occurred in these wells due to the fluids used during those interventions. The application of CCT has resulted in the removal of sand and lost clean-out fluids previously used.
This paper reviews the wells, which have had conventional cleanout methods done that were unsuccessful and provides the results of using CCT technology to restore well production thus reducing well interventions by 50% and OPEX savings up to 15%.
Application of a New IPR Model with a Comparison to PGOR Test and PLT Data to Evaluate Wells Productivity
Authors: Elyas Mohamed , Al Watyan Abdullah , Freile Daniel , Abba Abdessalem , Shati Jassim 
Published: December 2018

Abstract
In 2009 a new Inflow Performance Relationship (IPR) model "SPE- 124041"was built using simulation and field data sets. Reservoir simulation was used firstly to accurately select the best fit between the oil mobility function and the average reservoir pressure. The new IPR was developed based on the resulted oil mobility-pressure profile. Then, many field cases were used to develop an oil mobility-pressure relationship. Accordingly in this work, an attempt to apply the new IPR was proposed.
To check the applicability and accuracy of the new IPR model, multi-rate test with bottom hole pressure is required to plot the actual IPR curve. Many Portable Gas Oil Ratio (PGOR) tests integrated with ESP bottom hole pressure data and Flowing Bottom Hole Pressure (FBHP) surveys were used to create actual IPR curve for each well. Also, bottom hole pressure and flow profile obtained by Production Logging Tool (PLT) data for each entire producing interval in a layered reservoir system is used to plot each actual IPR curve. Then, the new IPR model was tested and compared to the most common IPR models to get the IPR curve for each well as well.
The applicability for different fields (KOC fields) of the new IPR model was tested and compared to the most common single point IPR models known in the industry (Vogel, Wiggins, and Sukarno). Many PGOR field cases were used for comparison. The best method for PGOR and PLT cases was the new method and that with average error of around 3.6 %, while the errors from the other models are higher than 4 % ranging from 4.5 to 5.3 %. For PLT cases.
To combine layered reservoir production testing, which could be conducted under pressure transient conditions with the inflow performance; it will help accurately to determine the optimum production rate for each well of interest. The results showed this method is accurate, reliable and simple. Is general for oil reservoirs, requires only one test point and has a wide range of application.
An Innovative Approach to Test Heavy Oil in Burgan Reservoir of Greater Burgan Field
Authors: Naik Vinay , Mudhfar Dalal , Pal Arindam , Karam E. M. , Attar Imad , M. Al-Haddad Saud 
Published: December 2018

Abstract
The Greater Burgan field is under production for more than 60 years and producing light to medium API oil. The objective of this paper is to explain an innovative method adopted in testing of Lower Burgan formation heavy oil and challenges faced during testing.
Heavy-oil zones are identified based on petrophysical logs interpretation and are located mostly near regional original oil-water-contact (OOWC). A previous study done on mapping of heavy oil zone for Burgan reservoirs and based on the maps, new process helped to identify expected heavy Oil zones in the upcoming and existing wells. To sustain future production target raised a need to explore flow potentials in the heavy oil reservoirs. A new methodology was developed by using a specially designed electrical submersible pump (ESP). Special testing pump (ESP) was designed and configured based on low API, high viscous oil, high angle deviation and reservoir characteristics from nearby wells.
The well was tested using specially designed ESP. The well produced for few days with Oil API 19-20 and flowed with a rate of 650-800 BLPD with 40%-50% water cut. In the future, this zone could be put back on production.
Earlier for heavy oil Burgan reservoirs, the oil viscosity and density were measured from downhole fluid sampling in few of the wells. However, there are uncertainties on how oil properties change with pressure. For the first time in Greater Burgan field, using specially designed ESP was a remarkable success for initial testing of heavy oil reservoir close to regional OWC.
Experimental Investigation of Steam-Alkali Flooding with Borax: A Case Study on Bati Raman Oil Field
Authors: Hashim Noori Wildan , Cinar Murat , Salehian Mohammad , Alkouh Ahmad 
Published: December 2018

Abstract
Steam injection is one of the well-known thermal recovery processes that has been extensively applied to heavy oil reservoirs. Several efforts have been made to understand theoretical and practical aspects of steam injection and alkali flooding. However, the detailed information about the performance of steam-alkali flooding in field applications has not been deeply addressed yet. In this sense, in order to shed light on the background and applications in this area, this study comparatively investigates the efficiency of different strategies of pure steam injection and cyclic steam-alkali flooding in Bati Raman oil field, Turkey.
Three experiments were conducted to evaluate the advantage of steam-alkali injection compared to pure steam injection for an 11.6° API Bati Raman crude oil. The steam injection system consists of two reservoirs for water and the alkali solution, an electrical pump, and an electric steam generator. Those three experiments are as follows; conventional pure steam injection, cyclic injection of steam and alkali solution 4.0 wt%, and cyclic injection of steam and alkali solution 8.0 wt%. Steam was injected with the rate of 10 ml/min at 110°C and the system pressure was set to be the atmospheric pressure. The liquid produced from the separators is sampled periodically to determine the oil recovery.
Observation of sand packs after the experiments indicates the tendency for steam channeling in the vertical direction around the upper thermocouple. Since the upper thermocouple was inserted after the sand packing operation by pressing and rotation, steam could be passed through these channels without entering the all pores in the porous media. The average oil recovery by conventional pure steam injection, steam-alkali solution 4.0 wt% injection, and steam-alkali solution 8.0 wt% are 8%, 3% and 5.5% OOIP (original oil in place), respectively. This indicates that although the oil recovery in conventional pure steam injection was maximum, increasing the alkali concentration in the aqueous solution from 4% to 8% has caused the improvement in the recovery.
The theoretical and practical information is supported by the experimental examples to evaluate the performance of different steam-alkali flooding strategies with Borax in heavy oil reservoirs of Bati Raman. This study also examines the challenges of steam-alkali flooding in extremely heavy oil reservoirs and explains that the pure steam injection is preferred due the insufficient change in interfacial tension during Borax injection process.