bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wettability Alteration in Reservoirs: How it Applies to Alaskan Oil Production
Authors: Thyne Geoffrey 
Published: April 2016

Abstract
The natural decline in oil production in Alaskan reservoirs is challenging producers to find methods to extend production. The current stage of reservoir development has reached the point where consideration of enhanced oil recovery methods is appropriate. Such methods could include CO2, chemical, microbial or thermal recovery. However, these methods require significant capital and/or operational investment. This paper evaluates the application of wettability alteration for Alaskan reservoirs by changing injection water chemistry also known as advanced water flooding. We use empirically-based screening and scoping methodologies to evaluate the suitability, cost and benefits of advanced water flooding for Alaskan reservoirs using public domain data.
First, laboratory and field examples of successes and failures are considered. Using this basis, a theory is developed that directly links water chemistry and reservoir wettability. The theory also illuminates the key characteristics of the reservoir that control wettability. We use empirically-based screening and scoping methodologies to evaluate the suitability, cost and benefits of advanced water flooding for Alaskan reservoirs with sufficient public domain data. The screening tool is built on empirical data from laboratory and field tests that identify the critical factors contributing to incremental production. The scoping tool uses a modified Kinder Morgan approach (dimensionless recovery curve) to evaluate the economic case for each reservoir.
The first field-scale tests of this technique were conducted by BP in the Endicott reservoir on the North Slope and produced good results by lowering the salinity of injection water. Those tests showed that alteration to injection water chemistry can increase recovery significantly. These results have been duplicated in laboratory and field tests in other locations. The tests were conducted without an understanding of the fundamental mechanisms nor optimization of the injected water chemistry, and thus represent minimum recovery. We find the increased recovery is profitable for several fields depending on assumptions about water sources, water treatment costs and rates of injection.
The successful approach to advanced waterflooding requires several key steps: screening the formation to evaluate the applicability of the technique, simple laboratory tests to determine the optimal water chemistry and quantify the increased recovery, economic evaluations to estimate costs and benefits, and finally, comprehensive geochemical models to design the wettability-modifying fluids. The technique has several advantages compared to current methodologies for wettability alteration including substantially lower costs, no environmental impacts and ease of application.
Coupling Low Salinity Water Flooding and Preformed Particle Gel to Enhance Oil Recovery for Fractured Carbonate Reservoirs
Authors: Alhuraishawy Ali K. , Imqam Abdulmohsin , Wei Mingzhen , Bai Baojun 
Published: April 2016

Abstract
The recovery of oil from carbonate reservoirs is usually low due to their extreme heterogeneity caused by natural fractures and the nature of the oil-wet matrix. Low salinity water flooding (LSWF) and preformed particle gels (PPGs) control conformance are two novel technologies that have recently drawn great interest by the oil industry. We developed a cost- effective, novel, enhanced oil recovery (EOR) technology for carbonate reservoirs by coupling the two technologies into one process. The objective of this paper is to provide a comprehensive understanding of the combined technology and to test through laboratory experiments the extent to which the coupling method can improve oil recovery. The laboratory experiments showed that the optimum water salinity for the application of the coupled method was 0.1 wt. % NaCl under experimental conditions. The water residual resistance factor (Frrw) increased as the water salinity and the fracture width decreased. The oil- wet carbonate cores provided a higher improved oil recovery than a water-wet carbonate cores during LSWF. The decrease in fracture width resulted in a higher oil recovery factor. Compared to traditional bulk gel treatments, PPG forms stronger plugging but will not form an impermeable cake in the fracture surface; therefore, PPG allows low salinity water to penetrate into the matrix to modify its wettability, thus producing more oil from the matrix. Results also show that oil recovery increased by 10 % during LSWF after the second waterflooding. Additionally, when PPG was injected, another 8 % of oil recovery was gained. As a result, combined the LSWF and PPG increased oil recovery by 18%. LSWF can increase only displacement efficiency but has little or no effect on sweep efficiency, while particle gels can plug fractures or in high-permeable channels to improve sweep efficiency but have little effect on displacement efficiency. The coupled method bypasses the limitations of each method when used individually and improve both the displacement and the sweep efficiency.
Partial-Equilibrium Simulation of Gas Hydrate Accumulation in the Sedimentary Strata Under the Sea
Authors: Zhang L. , Li X. , Zhang Y. , Xu Y. , Gong Z. H. , Jiang H. N. , Ren S. R. 
Published: April 2016

Abstract
Comprehensively understanding the gas hydrate accumulation mechanism is significant for the investigation of subsea gas hydrate reservoir which can provide further guidance for the hydrae exploration and development as well as the safe deep-water drilling. In this paper, a preliminary conceptual model is established to study the characteristics of gas hydrate accumulation in the typical shallow formation under the sea using a reservoir simulation method. A partial equilibrium reaction model based on the phase equilibrium of gas hydrate is used to describe the trigger mechanism of hydrate formation when methane from deep formation migrates into the upper hydrate stability zone under the seabed. Two cases are simulated for comparison, one considering the barrier effect of cap rock at seabed while the other assuming a cold spring at seabed. The simulation results indicate that in the cap rock case, a thick hydrate layer tends to be formed in the upper subsea formation but with a relatively smaller hydrate saturation, while in the case of cold spring, nearly 90% of methane from deep reservoir would leak into the sea water, nevertheless the long-term slowly gas driving water process is favorable for generating high hydrate saturation. Generally, low flux of methane gas, cap rock barrier, deep water depth, and small geothermal gradient below mud line are beneficial to forming valuable hydrate reservoirs with larger thickness and high abundance. This study has proven that the reservoir simulation method can be an effective tool to simulate the process of gas hydrate formation and accumulation in the shallow formation under the sea, which deserves for further study.
Integrating Enhanced Oil Recovery and Carbon Capture and Storage Projects: A Case Study at Farnsworth Field, Texas
Authors: Balch Robert , McPherson Brian 
Published: April 2016

Abstract
The Southwest Partnership on Carbon Sequestration (SWP) is one of seven large-scale demonstration projects sponsored by the U.S. Department of Energy. The SWP has a goal of permanently sequestering more than 1,000,000 metric tonnes of CO2 in an active EOR project in a mature waterflood in the Anadarko basin. The CO2 for this project is anthropogenically sourced from a fertilizer and an ethanol plant. As of the end of 2015 the field has 13 CO2 injectors and has sequestered 386,695 metric tonnes of CO2 between October 2013 and July of 2015. Goals of the project include optimizing the EOR/storage balance, ensuring storage permanence, and developing best practices for carbon storage utilizing man-made CO2.
The field site provides an excellent laboratory for testing a range of monitoring technologies in an operating CO2 flood since field development is sequential and allows for multiple opportunities to record zero CO2 baseline data, midflood data, and data from fully flooded patterns. The project has acquired data at a number of scales including a 42 mi2 3D seismic survey, baseline and repeat 3D VSP surveys centered on three injection wells, cross-well tomography baseline and repeat surveys between injector/producer pairs, a borehole passive seismic array to monitor for induced seismicity, a distributed temperature system, and bottomhole pressure and temperature sensors. The project has drilled three wells in the field, and has acquired over 750 ft of core in the Morrow B reservoir interval and associated caprock units. Additional monitoring focuses on CO2 soil flux, groundwater chemistry, reservoir fluids chemistry, and aqueous and gas-phase tracer studies.
All acquired data have contributed to detailed geologic models used for fluid flow and risk assessment simulations. 3D VSP and cross-well data with repeat surveys have allowed for direct comparisons of the reservoir prior to CO2 injection and at eight months into injection, with a goal of imaging the CO2 as it moves away from injection wells. Additional repeat surveys at regular intervals will continue to refine direct CO2 imaging as production and injection data are integrated with newly acquired and interpreted data. All models are regularly updated. In this paper the project goals will be outlined, progress towards goals enumerated, and current geologic and simulation models will be introduced. In addition, initial results from time-lapse monitoring of movement of CO2 in the reservoir will be discussed.
A New Analytical Solution for Predicting Oil Rate Vs. Time in Waterflood Using Various Injection Plans
Authors: Chen Yuting , Ershaghi Iraj 
Published: April 2016

Abstract
This paper introduces a new method and its analytical basis for predicting oil rate vs. time for fields under water flood or water influx. Application to actual waterfloods and water influx cases are included as case studies. Majority of analytical solutions on this subject discussed in the literature have in the past focused on extrapolation of WOR or water cut vs. cumulative production. When it gets to forecast oil rate vs. time, many practitioners have resorted to Arps1 type decline analysis methods. The shortcomings of decline analysis techniques are primarily their lack of honoring the physics of the immiscible displacement processes.
In the application of the proposed method for predicting into the future, assumptions need to be made about the injection rate plans or estimated influx rate based on past histories relating injection or influx to the gross production rates.
Analysis of SEAM Phase I Data and the Related Challenges
Authors: Xue Chenguang , Aminzadeh Fred 
Published: April 2016

Abstract
The salt related traps (sub-salt or slat flank) in the deep water of the Gulf of Mexico (GOM) has a pronounced impact on reservoir exploration and appraisal. It is, therefore, vital to do interpretation and attributes analysis on the seismic data to capture detailed reservoir structure and properties, as that is one of the core goals of the SEAM Phase I Project provided by the SEG. In this paper we will show how using Petrel and OpendTect is one of the keys to achieving that objective.
The strong seismic interpretation tools of OpendTect can help track seismic events and eventually guide us in selecting horizons. Furthermore, the novel approach of using the Supervised Neutral Networks can help us recognize the subsalt zone and faults structure. When the interpretation results, bolstered by additional measured information, are input to Petrel, it can offer the possibility of imaging the subsalt and increasing data analysis for this area.
Some interpretation and analysis results have been generated to represent our targeted area of the GOM. The stratigraphic variation and reservoir properties, as well as the feature of the salt domain, will be detailed in the results. Our analyses have revealed five major horizons in this area, three of which intersect with the salt body. The shape of the salt body is irregular, with a rugged top, and overhangs on both east and west sides. We will continue with confidence towards the end goal of imaging the area, lithology, and to distribute properties that include porosity, density, and fluid saturations (oil, water, and gas). This in turn will help us properly guide the reservoir development in that specific environment.
Our innovative methodology has rewarded us with an efficient way of combining two powerful commercial software programs to perform data analysis and ultimately enable us to image the complex structure of the salt body.
The Lexicon of Recompletion: Empirical Justification for Refrac, Reentry, or Remediation in the Bakken/Three Forks Play
Authors: Gullickson Geoffrey , Ruhle William , Cook Peter F. 
Published: April 2016

Abstract
The horizontal Bakken/Three Forks play of the Williston basin has a long standing history of recompletion dating back to the late 1980s. While rapid evolution of horizontal completion design has allowed expansive Bakken/Three Forks unconventional acreage positions to reach economically viable levels, existing legacy completions have historically been difficult to invigorate to modern productivity expectations. Although recompletion is nothing new to the oil and gas industry, the techniques applied are highly variable and historically may carry disappointing and unpredictable results. As a need for better understanding of principle well development continues to evolve, so do better techniques in legacy well recompletion tactics to enhance both developed and undeveloped assets.
Within the Bakken/Three Forks play, legacy development drilling and completion tactics are vast with significant productivity variances. Industry mindshare often incorrectly groups all recompletion methods into a single category. Differences in technical application, and associated value added per input cost, require subcategorization of recompletions to improve well productivity. A holistic identification process is required to appropriately match the service intensity associated with refracturing, reentry, or remediation to project costs and asset potential.
The focus of this study is to compare and evaluate the production results attained from recompletions in the discrete subcategories of well refracturing, reentry, and remediation. Empirical datasets will be presented to define the project inputs and production value capture associated with each recompletion type. By integrating these workflows, enhanced recompletion design and execution can create value at previously unattainable commodity price levels.
A comprehensive completion and production database of horizontal Bakken/Three Forks wells dating from 1987 to present has been developed to facilitate recompletion selection, design, and predictive production forecasting. Proprietary software that automates production analytics, combined with manual canvassing of over 10,000 wells, has provided an innovative method to cross-examine the Bakken/Three Forks play. By combining a multivariate assessment with probabilistic results, novel recompletion propositions can be successfully matched to project needs.
Steam-Flood Production Optimization Using an Innovative Steam Quality Sensor
Authors: Kerr Robert P. , Medizade Mason M. , Gleason Brian D. 
Published: April 2016

Abstract
Many oilfields operators across California and the world use steam as an injection fluid to recover high viscosity heavy oils. The steam injection process is done intermittently in cyclic steam injection and continuously in steam drive or Steam Assisted Gravity Drainage, SAGD, applications. The latent heat of vaporization of steam plays an important role in transferring heat to the oil, water, and reservoir rock and as a result reducing the oil viscosity making the oil trapped by viscosity, capillary and permeability effects, mobile. In cyclic steam injection, since the injection and production takes place in the same well, determining the optimum soak time at which flow back needs to be initiated is very critical, specifically in low permeability reservoirs such as California's diatomite having small well spacing and needing hundreds of short steam cycles. In this case, the overall success depends on ultimate oil recovery at the end of each flow back cycle. Additionally, knowing steam quality on the injection and on the production sides contributes to better heat management and better production practices, improving economics of the steam injection process. In this study, development and laboratory testing of a novel steam quality sensor, a tuning fork densitometer, are presented. This non-nuclear density sensor technology is adaptable to high temperature operation and has high sensitivity, making it ideally suited to measuring the small changes in density that occur due to varying steam quality. The application of this technology for cyclic steam injection, steam drive, and geothermal steam production are discussed. The sensor can be packaged for use down hole and at surface for continuous measurements of steam quality on injection as well as production applications.
Determination of the Stability of Asphaltenes Through Physicochemical Characterization of Asphaltenes
Authors: Prakoso Andreas , Punase Abhishek , Klock Kristina , Rogel Estrella , Ovalles Cesar , Hascakir Berna 
Published: April 2016

Abstract
Significant effort has been dedicated to understand the variables affecting asphaltene precipitation. Based on years of research, it is well known how variables such as temperature and pressure can affect the deposition of asphaltenes. However, much less is understood about the effect that asphaltene characteristics have on the tendency towards precipitation of different crude oils. We characterize extensively a series of n-pentane extracted asphaltenes and construct novel correlations with the stability of their corresponding crude oils.
11 different bitumen and crude oil samples are characterized first with API gravity and viscosity measurements, and thermogravimetric and differential scanning calorimetric analyses (TGA/DSC). The weight percentage of the asphaltenes in bulk samples are determined through n-pentane precipitation. The molecular structure of the asphaltenes is investigated with Fourier Transform InfraRed (FTIR) spectroscopy. Asphaltene stability is measured by ΔPS and by determining the Asphaltene Solubility Profile. The impact of hydrogen deficiency, heteroatom content and solubility distributions on other properties such as viscosity and aggregation behavior is also explored.
It has been observed that there is weak relationship between the asphaltene content and API gravity or viscosity of the bulk samples. The weight percent of the light, intermediate, heavy, solid, and ash fractions of the asphaltenes, defined with TGA/DSC experiments, indicate that the carbon rich solid component of the bulk samples that can decompose over 550 °C, correlate with the weight percent of the asphaltenes in bulk oil. The ash content of the bulk oil, which is mainly composed of heavy metals like sulfur, nickel, and vanadium, is correlated to the amount of asphaltenes precipitated out of the oil. Moreover, FTIR and solubility profile analyses reveals that the polarity of the asphaltene molecules is affected not only by its molecular composition and structure but also by its interactions with other crude oil components.
This study discusses the impact of the physical and chemical properties of crude oils and their asphaltenes on asphaltene precipitation. Several asphaltene deposition mechanisms are developed and validated for 11 different crude oil and bitumen samples with different asphaltene contents, thereby providing important and fundamental insight into asphaltene related problems.
Low Viscosity Cement Slurry for Improved Placement in Narrow Annuli
Authors: Campbell Rianne , Lauper Stephen 
Published: April 2016

Abstract
When cementing wells with small clearance between casing and borehole, or between casing and previous casing, friction pressure becomes a limiting factor in cement placement. The aim of this study was to reduce pressure on these jobs to allow increased rate and more effective cement placement, without compromising slurry integrity or increasing wait-on-cement time. This was achieved through the development of a reduced-density, low-viscosity slurry that maintained many of the same characteristics of the previously-used cement slurries. The particular focus of this project was on coiled-tubing drilling (CTD) production liners, as these well geometries frequently have a very narrow annular gap. In addition, the length of coiled tubing at surface contributes to higher overall pressures than cementing with conventional rigs.
The local slurry previously used on these jobs was a 15.8-lbm/gal (ppg) Class G-blended slurry with gas migration control. With the aim of reducing job pressures, both the density and the viscosity of the slurry were reduced. The density was reduced from 15.8 ppg to 15.3 ppg, while maintaining the gas migration control additives. To ensure that wait-on-cement time was not negatively affected, some of the Class G cement was replaced with microcement to aid in the rapid set of the slurry. Results of initial lab testing were modeled in cement job design software to assess hydraulic results and confirm sufficient displacement efficiency. The lab results from the 15.3-ppg slurry were also compared to those of the 15.8-ppg slurry to ensure there were no reductions in quality. The slurry was then used successfully on several jobs to confirm the pressure reduction, including cementing production liners through coiled tubing (2⅜-in. liner in 3¼-in. open hole), and cementing casing repair tiebacks with conventional rigs (such as 5½-in. casing inside 7-in. casing). Case studies are included.