bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of Daily and Seasonal Cycles in Solar-Generated Steam On Oil Recovery
Authors: van Heel A. P. , van Wunnik J. N. , Bentouati S. , Terres R. 
Published: July 2010

Abstract
Steam-injection projects located in areas with abundant sunshine can exploit solar energy to generate steam, instead of burning gas. Using mirrors, sunlight can be concentrated and used to heat water flowing inside a pipe to steam-temperature at high pressure. This solar-generated steam is only available during the day, causing a day-night cycle in the steam-rate, and is also affected by seasonal variations in solar energy, causing a summer-winter cycle in the steam-rate.
Using both analytical modelling and thermal reservoir simulation, we investigate the impact of the daily and seasonal cycles in steam rate on oil recovery. We compare the oil recovery from solar-generated steam and the recovery resulting from a continuous and constant-rate steam-injection, as obtained by burning gas, for instance.
Our analytical model for the periodic heating of matrix-blocks in a fractured reservoir shows that for fractured reservoirs with a typical fracture-spacing larger than one metre, the impact of daily cycles in steam-injection can be ignored.
Using thermal reservoir simulation, we also compare oil recovery from two representative models of realistic reservoirs: a fractured reservoir (recovery mechanism: thermally-enhanced gas-oil gravity drainage) and a non-fractured reservoir (recovery mechanism: steam-drive), for both steam-injection profiles: constant-rate and cyclic-rate. Our simulations show that the seasonal cycles in the solar-generated steam rate are reflected as seasonal cycles in the oil-rate.
The simulation results indicate that for the same cumulative amount of steam injected (during the same time-span), the oil recovery from solar-generated steam-injection and that from constant-rate steam-injection are essentially the same, both for the fractured reservoir and for the non-fractured reservoir. Therefore, from a subsurface oil-recovery point of view, solar-generated steam provides a viable alternative to constant-rate steam-injection.
Investigation of ASP Flooding Efficiency on Artificial Sandstone Cores: Homogenous Case
Authors: Al Shahri H. , Liu J. , Liu K. , Clennell M. B. 
Published: July 2010

Abstract
This work is a part of a fundamental study investigating the efficiency of the alkaline- surfactant-polymer (ASP) flooding process. While heterogeneity in pore structure is a key concern of our research, it is necessary first to have a clear understanding of the baseline behavior when porosity, permeability and throat size are tightly controlled. This control was achieved by manufacturing a homogenous carbonate-cemented sandstone using the calcite in-situ precipitation system (CIPS). We present the multiphase flow properties of the artificial CIPS rocks, including previously unpublished results on oil/water capillary behavior and relative permeability.
In the core flooding experiments described here we used zero clay content and kept the same throat size and pore size distribution and kept the same chemical composition of the ASP slug. The polymer that was used in the flooding was polyacrylamide (1560 ppm) and the surfactant was alpha olefin sulfonate (1% w/w) and the alkaline was NaOH (0.5% w/w). Along with ASP floods, two surfactant floods were run with concentrations of 1% and 0.1% (w/w). Two identical specially fabricated CIPS carbonate cemented cores were used. The silica grains of both cores are primarily silica cemented by calcite. Both cores have a permeability of 1.8 Darcy and porosity of 19.4%. The only experimental variable was then the oils type and we choose oils such that their viscosities have close values. Australian heavy crude oil (18 API) and highly refined paraffinic oil (Ondina 68) were used in the core flooding study.
Two ASP floods were run, and although all the physical parameters were kept same except oil type, the outcome was significantly different. While recovery of both the refined oil and the crude oil was the same after initial waterflood, the crude oil was mobilized more by the ASP process, through both microemulsion and banking processes. The experiment with the refined paraffinic oil produced less ultimate recovery, and only the microemulsion process was significant.
Early Miscible Hydrocarbon Gas Injection in Abu Dhabi Heterogeneous Carbonate Reservoir
Authors: Dawoud Ahmed , El Mahdi Ahmed , Bidinger Curt , Basioni Mahmoud , Ayoub Mohammed , Al Shehhi Abeer Saleh , Khoori Suaad Abdulla 
Published: July 2010

Abstract
Development studies of a heterogeneous carbonate reservoir in Abu Dhabi-United Arab Emirates based on 10 years of data from eight oil producers and one pilot water injection well concluded that mobility enhancement of the injected phase would be a key factor of effective pressure support and recovery. Development studies of different options concluded that miscible hydrocarbon gas injection would give the highest recovery and was adopted for implementation.
Variation of the reservoir fluid properties with presence of a gas cap at the crest was reported and the Minimum Miscibility Pressure (MMP) of the injected miscible hydrocarbon gas reported to be very close to the reservoir pressure. Simulation studies indicated that miscibility would not be sustained and gas percolation into the gas cap would always be there. The studies concluded that gas injection near the OWC would give better chance to benefit from gravity segregation of the percolated gas.
Five spot inverted pattern at the crest in the area below the gas cap and staggered line drive WAG down flank in the highly under-saturated oil were selected as the optimum development option that was implemented in Phase I development area. All the development wells were completed using long radius open horizontal hole completion technique for both the producers and injectors. Hydrocarbon associated gas was processed and injected in its rich composition.
Collected bottom hole samples after one year and half of injection indicated arrival of the miscible front into location of a newly drilled well offset to a gas injector suggesting successful miscibility. Project has been in progress achieving the target production plateau with some anomalies of high GOR. Surveillance plan was set to closely monitor front movement of both gas and water in key observation wells.
This paper presents a case history of an early miscible hydrocarbon gas injection project in a newly developed heterogeneous carbonate reservoir and observations after four years of production and injection.
Modified SAGD In Multiple Zones At Mukhaizna
Authors: Malik Sanjeev , Zhang Y. M. , Al Asimi Mohammed , Gould Thomas L. 
Published: July 2010

Abstract
The Mukhaizna heavy oil field in the Sultanate of Oman has three distinct zones that need steam injection to enhance oil recovery. A new geocellular based reservoir description was prepared as the starting point to evaluate the performance of these three zones; UG2A, UG2B, and MG to different injector and producer configurations. The major challenge was to ensure good production rates without compromising recovery efficiency. The three zones are separated from each other except in a few places where the two zones UG2A and 2B communicate.
During the flood design, producers with horizontal laterals were considered for each of the three zones. However, determining a method for steam injection that delivered recoveries similar to steam assisted gravity drainage (SAGD) was a challenge. A thermal reservoir simulation model was used to evaluate various configurations including horizontal and vertical injectors.
The final design called for commingled vertical injectors positioned between offset horizontal producers with three laterals stacked vertically. This design created a new modified SAGD recovery process for the reservoir. A steam chamber is created above each horizontal lateral, but the steam arrives from the side. One advantage of this design is the ability to control steam in each vertical injector. With advanced surveillance techniques to determine locations of early steam breakthrough, vertical injectors can be controlled to optimize recovery.
This paper will show the design options considered and their estimated recovery. Then the modified SAGD design, implemented at Mukhaizna, will be compared to current production performance in a selected area of the field which has been under injection for around 2 years. Field performance, which will be presented as rate versus time, and, also using dimensionless plots is tracking the thermal model based design quite nicely. The use of surveillance methods to control injection is also discussed.
Integrated Usage of Surveillance Data for Estimating Cap Rock Integrity and Heat Distribution during Steam Injection in a Fractured Carbonate Reservoir
Authors: Schoofs S. , Lawati M. , Engen G. , Salmi K. , Quseimi I. , Kindy F. , Marsden C. , Ita J. , van der Heyden F. H. , Bauer A. 
Published: July 2010

Abstract
EOR operations involving steam injection lead to heat being transferred to the reservoir, which expands, and the expansion is transferred to the overburden. This can induce a cap rock breach and steam/gas seep, leading to inefficient development and higher recovery costs. Thermal expansion could also re-activate faults, potentially affecting surface facilities. In a forward-modeling study of the cap rock integrity during steam injection in a giant fractured carbonate oil field in Oman the possible failure mechanisms of the cap rock were illustrated. Further, opportunities for cap rock and reservoir surveillance were identified. During a first phase steam development of the field a variety of well and reservoir surveillance data are being gathered, including (GPS and InSAR) surface deformation measurements, micro-seismic activity, and (distributed) temperature and saturation logs. Integrated usage of the surveillance data allows for calibration of and comparison between two geomechanical models. The geomechanical models are employed to monitor the cap rock integrity during the steam operation on a regular basis, and to derive the heat distribution (evolution) within the reservoir. To this end, both forward and inverse modeling workflows have been developed. The results of this study may trigger the development and evaluation of alternative steam injection schemes (well spacing, injection rates).
Novel Methodology for Full-Field Production Forecasting in a Large Steamflood Project in Sultanate of Oman
Authors: Wang Wei , Zhang Eamon , Fitchen Bill 
Published: July 2010

Abstract
Full-field production forecasting is a key requirement for facilities design and economic analysis during development of a Field Development Plan (FDP). However, forecasting using relatively fine-grid thermal simulation models with over one million grid blocks can require days or weeks to complete a run. Within the timeframe of a typical FDP project, teams must often evaluate multiple geologic and reservoir engineering scenarios, development concepts, and uncertainty ranges in high- sensitivity variables in terms of their impact on production streams, costs, and overall project economics. During this evaluation process, fast and flexible forecasting methods are favored over slower but perhaps more accurate methods.
Mukhaizna field is a giant heavy oil field in South Sultanate of Oman and is presently under steamflood. Following a period of cold production development involving the drilling of 75 horizontal producers and resulting in very low recovery, a steamflood FDP was developed over a period of six months. Based on this FDP, drilling of hundreds of horizontal producers and thousands of vertical injectors is planned for the next 20 years. Mukhaizna is the first large-scale commercial steamflood to use horizontal producers and vertical injectors.
Full field production forecasting for Mukhaizna was performed using a novel, fit-for-purpose workflow. Pattern-scale, fine- grid geologic models representing areas of distinctive flow unit and permeability architecture were built and simulated to develop pattern production type curves. Full-field production forecasts were obtained by scaling up production streams from type-curve simulation using a scale-up tool prototyped in Excel. Inputs to the scale-up tool included pattern STOOIP, drilling sequence/schedule, production targets, and facilities constraints. Once type curve simulation was completed, any field development scenario could be forecasted within a few hours. This paper 1) describes how the type-curve models were defined, generated, and simulated; 2) how the detailed scale-up methodology was developed and applied in the Mukhaizna FDP.
Case Study of Alkali - Polymer Flooding with Treated Produced Water
Authors: Yang De-hua , Wang Jian-qiang , Jing Li-xi , Feng Qing-xian , Ma Xian-ping 
Published: July 2010

Abstract
It is very challenging to run polymer/alkaline flooding in a high water-cut (Sw&gt;96%) and viscous oil (μ:114mPa.s at 60°C) reservoir using produced water to mix chemicals. This work is aimed at applying Alkili-polymer flooding under a circumstance there is a shortage of fresh water supply. The selected chemicals are compatible to hard components such as Ca and Mg in the produced water. A less polymer solution degradation in the treated produced water is obtained. A pilot test program was carried out in Yangsanmu oilfield from 1998 to 2008.
During the pilot test, based on lessons obtained, a series of new technologies were developed (1) to reduce active composition and in produced water, the produced water was air-bubbled extensively and improved water quality. (2) Removed chemicals the produced water was filtered using sandy filter. (3) using anti-salt polymer to replace previous used pyacrylamide to increase polymer solution viscosity. (4) using active alkaline to replace dicarbonate on high acid value oil (1.84mgKOH/g oil). As a result, the IFT decreased from 0.1 to 0.001 mN/m and no more crust. The core test showed that the oil recovery by selected alkali-polymer solution increased 22.8% even we started it at a water cut of 90%. The optimized chemical system is 1% alkaline plus 0.15% polymer.
The pilot was run with a test area of 0.71km2, including 4 injectors and 18 producers. The solution was prepared in a central station and delivered to injectors by pipelines. Total injected polymer solution was 1.1 million cubic meter with concentration 0.15%, and alkaline solution was 0.72 million cubic meter with concentration 0.8%. About 6 moths later, dynamic monitored residual oil saturation with fiber glass casing in 2 producers showed the residual oil decreased from52.8% to39.6%. Injecting pressure increased by 2MPa and water cut decreased from 96.4 to 71.6%. The total oil incremental reached 0.94 million bbl.
Modeling Formation Damage due to Flocculated Asphaltene Deposition through Dynamic Displacement
Authors: Rezaian A. , Kordestany A. , Jamialahmadi M. , Moghadasi J. 
Published: July 2010

Abstract
The deposition of asphaltene in porous media and their interaction with rock and fluids represent complex phenomena which needs to be investigated under dynamic flowing condition. It could occur by reducing mobility (λ=k/μ) in three probable mechanisms of asphaltene included damage: a) blocking pore throat, b) altering wettability, and c) increasing the reservoir fluid viscosity and can have strong effect on oil production through heavy oil recovery, miscible flooding, and even primary recovery. Many experiments were performed by researchers to determine the amount of deposition and permeability decline but the boundaries in which the asphaltene deposited in oil or at the pore surface was not determined, thus the models introduced have some difficulties using all parameters.
In this paper, a mathematical model is developed constructing to simulate rock-fluid interactions describing permeability decline due to asphaltene deposition. The model considers the second stage (if separated into liquid phase precipitation and pore surface deposition) of asphaltene deposition in which n-hexane used to flocculate asphaltene particles in order to determine the effect of deposition on sandstone rock due to changing of pressure, temperature, and composition of reservoir oil. The influences of various injection rates and concentrations are considered carefully.
This model simulation and corresponding analytical method is applied using laboratory data gained by performing various dynamic displacement experiments with pre-separated oil asphaltene content resulted a close agreement so it could predict the trend of permeability reduction due to deposition of asphaltene. So the procedure of matching the parameters is described here.
This model can be used for analysis of laboratory core tests of formation damage due to flocculated asphaltene particles. Thus, the present study leads to a new insight into the mathematical explanation of flow behavior in porous media.
Probabilistic History Matching With the Capacitance-Resistance Model in Waterfloods: A Precursor to Numerical Modeling
Authors: Sayarpour M. , Kabir C. S. , Sepehrnoori K. , Lake Larry W. 
Published: July 2010

AbstractSeveral equally probable sets of uncertain reservoir parameters can normally match a production history. Such equiprobable history-matched solutions (EPHMS) are a way to estimate the uncertainty in hydrocarbon-recovery predictions. Ordinarily, time and resource limitations permit evaluation of only few of the EPHMS, thereby reducing reliability of predictions of numerical models. As a precursor to comprehensive numerical simulations in a probabilistic frame, we suggest the use of capacitance-resistance model or CRM. In CRM only injection and production rates are needed.The CRM is a fast analytic tool for history matching and optimizing waterfloods. In this study, we used CRM and a Buckley-Leverett-based fractional-flow model to rapidly generate many EPHMSs. The EPHMS represent a unique combination of major reservoir variables, such as residual saturations, endpoint mobility ratio, oil and water in-place volumes, and recoverable oil.We used production data from two matured waterfloods and a synthetic field (Synfield) to evaluate the EPHMS. For most cases, one thousand EPHMS and the consequent cumulative distribution functions (CDFs) for several uncertain variables, including recoverable oil, were developed. We compared the CDFs obtained from EPHMS to that of 200 finite-difference simulations performed on the Synfield by changing porosity and residual saturations. EPHMS mimicked the same uncertain range of production forecasts used earlier in the finite-difference model. This approach attested to the goodness of CRM solutions and its ability to quantify reservoir uncertainty. Two field examples illustrated applications of the proposed approach at the field and pattern levels, and provided clues about the remaining oil and its monetary value.
Microbial EOR—Critical Aspects Learned From The Lab
Authors: Jackson Scott C. , Alsop Albert , Choban Eric , D'Achille Ben , Fallon Robert , Fisher John , Hendrickson Ed , Hnatow Linda , Keeler Sharon , Luckring Abigail , Nopper Rick , Norvell Joseph , Perry Michael , Rees Bethany , Suchanec David , Wolstenholme Sheryl M. , Thrasher Dave , Pospisil Gordon 
Published: July 2010

Abstract
DuPont and BP have been working together to develop Microbial EOR targeted at viscous oil in the Schrader Bluff formation on the North Slope of Alaska. The goal of this program was a 5% increase in the recovery factor. Mechanisms to be assessed in the original agreement included Viscosity reduction of the oil by transformation or degradation of heavy components in the oil – thus improving the oil – water mobility ratio.Drastic reduction (to ~&lt;0.01 dynes/cm) in the interfacial tension between water and the oil
After extensive fundamental research we have learned many critical aspects of microbial EOR that made the application of these two mechanisms to the Schrader Bluff formation impractical. Instead, we have demonstrated two site appropriate mechanisms that achieved, in the lab, the targeted increase in the recovery factor. Improved flow conformance and increased sweep efficiency by preferential plugging of high permeable zones thereby forcing water to produce oil from previously unswept parts of the reservoir.Reduced oil / rock surface tension and a subsequent reduction in the oil "wetting" the rock. This results in changes in the relative permeability of the oil and the water and ultimately lower residual oil saturation.
This paper describes the key laboratory tests used to evaluate these four mechanisms. The cornerstones of our work have been the detailed characterization of the waters, the oil, the formation matrix and the microbial community. In addition we describe our search for useful microbes isolated from a variety of environmental samples collected from the Milne Point Unit (MPU) of the Alaskan North Slope. These samples were taken over several years and included injection, production and power fluid waters. These samples were used to understand the temporal changes in the microbial populations and to provide inoculum for our enrichment cultures.
Our ongoing research has provided many insights into the appropriate application of microbial EOR. The unique aspects of each production area, the nature of the oil, the water, the formation matrix, and the background microbial population and their complex interactions must all be assessed when considering the potential application of microbial EOR. The amount of work discribed below for assessing potential MEOR mechanisms is extensive. However, this process has been streamlined and we have been able to assess new target reservoirs for potential MEOR treatments in about 6 months.
Reservoir Simulation of Steam Fracturing in Early Cycle Cyclic Steam Stimulation
Authors: Cokar Marya , Kallos Michael S. , Gates Ian D. 
Published: July 2010

ABSTRACT
In Cyclic Steam Stimulation (CSS), steam is injected above the fracture pressure into the oil sands reservoir. In early cycles, the injected steam fractures the reservoir creating a relatively thin dilated zone which allows rapid distribution of heat within the reservoir without excessive displacement of oil from the neighborhood of the wellbore. Numerical reservoir simulation models of CSS that deal with the fracturing process have difficulty simultaneously capturing flowing bottom hole pressure behaviour and steam injection rate. In this research, coupled reservoir simulation (flow and heat transfer) and geomechanics models are investigated to model dynamic fracturing during the first cycle of CSS in an oil sands reservoir. In Alberta, Canada, in terms of volumetric production rate, CSS is the largest thermal recovery technology for bitumen production with production rates equal to about 1.3 million bbl/day in 2008. The average recovery factor from CSS is between 25 and 28% at the economic end of the process. This implies that the majority of bitumen remains in the ground. Since the mobility of the bitumen depends strongly on temperature, the performance of CSS is intimately linked to steam conformance in the reservoir which is largely established during steam fracturing of the reservoir in the early cycles of the process. Thus, a fundamental understanding of the flow and geomechanical aspects of early cycle CSS is critical. A detailed, thermal reservoir simulation model, including dilation and dynamic fracturing, was developed to understand their effects on bottom hole pressure and injection rate. The results demonstrate that geomechanics must be included to accurately model CSS.