bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling the Geological Controls on Steam Flood Performance; An Example from a Field in South Oman
Authors: Shaikh MRF , Al Adawi R , Reiser H , Rocco G , Rodriguez F , Shuaili K , de Zwart AH 
Published: April 2012

Abstract
A field, located in south Oman, has a compact dome shaped structure with an oil column in excess of 200m. It produces highly viscous hydrocarbon from the fluvial Cambrian Haradh reservoir and represents an opportunity for Thermal EOR development. After an initial phase of steam injection, field data have shown that the response in the trial pattern is not homogeneous. In order to explain these observations a multidisciplinary effort has been undertaken to improve our understanding of the subsurface.
The information acquired in and around the injection area (an inverted 7-spot pattern), include connectivity trends from pressure data, temperature surveys, time lapse seismic, cores and well logs. After 20 months of steam injection a thermal response within the pattern is limited to only one producer well and two observation wells. The time-lapse seismic data is consistent with the field data observed from wells in the northern part of the pattern. The pressure data also indicate a predominant North-South connectivity trend within the pattern.
Four geological scenario models were built to test factors that may impact the understood distribution of temperature resulting from injection. The modelling workflow intends to assess the impact of 1) the internal structural dip and baffling lithologies within the Haradh Reservoir, 2) faulting within the Reservoir interval, 3) the Carboniferous Al Khlata immediately above the Haradh Reservoir and 4) the variation of Haradh Sandstone Facies and how these may impact fluid flow.
The models have been calibrated against historical data so as to ascertain if a given geological realization is a reasonable subsurface representation to reproduce the actual field production and pressure data. The results indicate that an individual scenario does not provide by itself an absolute explanation to the field observations to date. Instead, a combination of scenarios (fluvial facies and faulting) is considered to be a more feasible option to understand the field observations.
Macroscopic Recovery Mechanisms of In-Situ Combustion Process in Heavy Oil Fractured Systems: Effect of Fractures Geometrical Properties and Operational Parameters
Authors: Fatemi S. Mobeen , Kharrat Riyaz , Vossoughi Shapour , Ghotbi Cyrus 
Published: April 2012

Abstract
The In-Situ Combustion (ISC) as a thermal EOR process has been studied deeply in heavy oil reservoirs and is a promising method for certain non-fractured sandstones. However, its feasibility in fractured carbonates remained questionable. The aim of the present work was to understand the recovery mechanisms of ISC in fractured models and to evaluate the effect of fractures geometrical properties such as orientation, density, location and networking on the ISC recovery performance. Combustion parameters of a fractured low permeable carbonate heavy oil reservoir in Middle East called KEM; applied to simulation study. Simulator has been validated with KEM combustion tube experimental data and validated model modified to 3D semi-scaled combustion cells. It was found that in fractured models oxygen first flows into the fractures and then diffuses from all sides into the matrix. Combustion of the oil in the fractures produces water ahead of fracture combustion front which prohibits oxygen from early breakthrough through fractures into producer. Water imbibes into matrix and causes further oil drainage. Part of this oil imbibes into downstream matrices and the other part produces into producer through fractures. The oxygen diffusion/water imbibition based recovery mechanism is slower in production rates compare to conventional model recovery mechanism, and also results in lower quality of produced oil. It was found that ISC recovery was higher in the presence of networked fractures (presence of both longitudinal and traversal fissures) compare to the case of presence of either longitudinal or traversal fracture systems. Results show that ISC is more feasible in the case of densely fractured reservoirs such as those in the Middle East. Further, sensitivity analysis on air injection rate, formation thickness, injection well depth of perforation and also feasibility of water alternating gas (air), WAG, process for fracture model have been studied.
Wormlike Micelles for Mobility Control in EOR
Authors: Awang Mariyamni , Japper Azuraien , Kumar Sandeep , Dzulkarnain Iskandar 
Published: April 2012

Abstract
A major problem with polyacrylamide, the main polymer used in EOR, is its tendency to degrade under shear forces. Another polymer xanthan gum usually costs more than polyacrylamide and requires a biocide to prevent biodegradation. Micellar flooding has been reported extensively since the 70’s and as in the case of other chemical flooding, it has not been implemented widely due to the high cost of chemicals to form micelles. The high viscosity of the micelles also posed injection problems. However, strategic injection techniques can overcome the problem. The salinity of the formation water and temperature are also important parameters. All these usually restrict application of chemical EOR particularly surfactant and polymer flooding. However, current studies have shown wormlike-micelle surfactants such as those from cetyltrimethylammonium halides (CTAX) and cetylpridium halides (CPyX) can alleviate these problems. Wormlike micelles have been used in other areas such as home cleaner products and personal care products including shampoo and body wash due to its viscoelasticity. It also finds applications as fracturing fluids in oil fields. While earlier micelle studies proposed four or five components in forming stable micelles, the current studies showed that a surfactant and salt can form wormlike micelles. These micelles have the advantage of breaking and reforming under shear stress and therefore maintaining the viscosity. It is also viscoelastic and research has shown that viscoelasticity is able to reduce residual oil. This research studies the surfactants that can form wormlike micelles under high salinity, high temperature conditions and the salts that are required to form the micelles. Displacements studies conducted show good mobility control and work on injection strategy will be discussed.
Design of a Surfactant/Polymer Process in a Hard Brine Context: A Case Study Applied to Bramberge Reservoir
Authors: Tabary René , Douarche Frédéric , Bazin Brigitte , Lemouzy Pierre Maxime , Moreau Patrick , Morvan Mikel 
Published: April 2012

Abstract
Bramberge reservoir is a low temperature (40°C), high permeability (~1 Darcy) sandstone reservoir located in Germany. Waterflooded during several decades, oil production has been declining for the past few years. These conditions make this reservoir a good candidate for surfactant-polymer flooding.
Despite favourable attributes, the use of production brine, which exhibits very high hardness, as a re-injection fluid makes this project challenging and unique.
In this paper, we illustrate how this specific hurdle can be managed using a new strategy specifically developed for hard brines.
We show that surfactant/polymer formulations can be optimized in Bramberge re-injection brine despite its hardness with adequate properties for SP flooding (ultra-low interfacial tension and good solubility). The high level of divalent ions, and especially calcium ions, makes alkalis irrelevant for this project. We demonstrate using coreflood experiments that conventional injection strategies, successfully applied in soft brines (salinity gradient, etc…), and brine management options fail in these specific conditions because of the high chemicals adsorption. This high adsorption is showed to be strongly related to divalent ions.
We finally propose a successful alternative based on a careful selection of adsorption inhibitors. Using these additives, high oil recovery (94 %OOIP) was obtained together with low anionic surfactant and polymer adsorption. The overall technical performance is in line with conventional alkali-surfactant-polymer strategy in soft brine making this project very attractive and promising.
The process is currently in an optimization phase for pilot and field scale simulations allowing technical and economical optimization.
Alkali-Surfactant-Polymer Flooding Pilot Test in Southern Oman
Authors: Finol Jose , Al-Harthy Said , Jaspers Henri , Batrani Ahlam , Al-Hadhrami Hatim , van Wunnik John , Stoll Martin , Faber Rien , De Kruijf Alexander 
Published: April 2012

Abstract
Petroleum Development Oman is advancing a pattern flood pilot in a major sandstone field in Southern Oman that uses a chemical EOR flooding process to recover additional reserves. An EOR screening study showed that Alkali-Surfactant-Polymer is a viable technology for this viscous oil reservoir (90 cP). A successful ASP pilot test will pave the way to potentially implement the process in other sandstone fields in the Southern Oman Basin.
The ASP pilot test is a unique project in which two anionic surfactants have been specifically designed for the actual reservoir conditions. Laboratory tests indicated significant and comparable recovery from both outcrop and field cores. A high molecular weight polyacrylamide polymer designed to provide a favorable mobility ratio has also been tested at in-situ conditions. The primary objectives of the ASP pilot test are to validate laboratory results, demonstrate long term injectivity of the viscous ASP solution, reduce the range of technical and economic uncertainties associated with recovery efficiency and field operations and obtain data to calibrate dynamic models for accurate full-field predictions and economics.
The field pilot consists of a 1.4 acres inverted 5-spot pattern that includes 4 corner vertical oil producers, 1 central injector and 2 observation wells. The 53m producer-to-injector distance enables early ASP flood response (4 to 5 months) and ensures completion of the field trial within one year of injection. Injection/production facilities will be skid-mounted and located in the vicinity of the pilot wells. Pilot commissioning and first ASP injection is anticipated to start in mid 2014. This paper presents both subsurface and facility aspects of the ASP pilot test design, including four successful single-well ASP/SWCT field tests, one ASP flood MicroPilot, and the experimental results of oil-water-ASP emulsion separation experiments.
Modelling and Monitoring Experience on a 3-Year CO2 and Water Injection Pilot in a Mature Carbonate Field
Authors: Bourgeois Marcel J. , Gauer Pascal , Long Jerome , Prinet Catherine 
Published: April 2012

Abstract
In 2007, Total decided to launch a CO2 injection pilot, its objective being to prove the impact of CO2 injection on a mature depleted carbonate field. This field has been produced since 1982, mainly in natural depletion. The reservoir is Lower Cretaceous, low permeability carbonate rock with 20° API oil. The pilot pattern is an inverted 5-spot, with one central injector, 3 producers and one observer, the well spacing ranges from 300 to 700 m.
The main objective of the pilot was to observe and understand the effect of water and CO2 injection in a depleted carbonate reservoir, far below the Minimum Miscibility Pressure (MMP). This has been done in terms of microscopic oil recovery mechanisms, monitoring, and also field scale simulations. The microscopic work comprises secondary and tertiary CO2 SCAL data, and also a lean HC gas flood. PVT acquisitions include CO2 swelling tests, and slim tube data to estimate the MMP. Considering the risk of high mobility of immiscible CO2 in a heterogeneous reservoir, a WAG CO2 injection scheme was chosen and simulated.
This pilot was started in 2008, and has now 3 years of monitoring data. Breakthrough in HC phase was observed on the two proximal producers, but not on the most remote producer. Interestingly, as low salinity water was injected for a 18-month period after the CO2 injection, CO2 breakthrough was also measured in aqueous phase. SCAL data were matched by using alpha-factors (also called transport coefficients) in order to limit the stripping effect of the gas. Matching the 5-spot data enabled to quantify a strong multi-layer effect, as well as dissolution of CO2 in the injected water. From the lessons learned, we improved our understanding and capability to simulate and extrapolate WAG CO2 to other fields and conditions.
Minimum Miscibility Pressure Determination: Modified Multiple Mixing Cell Method
Authors: Teklu Tadesse Weldu , Ghedan Shawket G. , Graves Ramona M. , Yin Xiaolong 
Published: April 2012

Abstract
Hydrocarbon and non-hydrocarbon gas injection are among the most effective methods to enhance oil recovery. A key design parameter in any gas injection project is the minimum miscibility pressure (MMP). MMP can be measured in the laboratory with slim tube test, rising bubble apparatus and vanishing-interfacial-tension. Although laboratory measurements are more reliable, their high cost and longer period of time to get a few data sets made them less advantageous. There are numerous analytical, numerical, and empirical approaches devised to determine the MMP through studying thermodynamic behavior of reservoir and injection fluids in a given reservoir condition. Some numerical approaches need additional fluid and rock interaction properties such as relative permeability and capillary pressure.
Conceptually, miscibility between injected gas and reservoir oil can occur through three multi-contact mechanisms, namely condensing drive mechanism (CDM), vaporizing drive mechanism (VDM) and both condensing and vaporizing (CV) drive mechanism. Some models such as single-cell algorithm usually give overestimated MMP values since the model is based on the assumption that the drive mechanism is dictated only by CDM or VDM. In most cases, as we will see from the case studies of this research and reported by others as well, miscibility develops through both condensing and vaporizing (CV) driving mechanisms. Multiple mixing cell approach is a very effective way to handle CV drive mechanism. In this study, we modify the algorithm proposed by Ahmadi and Johns (2008), by including additional checking criterion. In spite of increased computational time overhead, our added checking criterion is found to be very useful to crosscheck the validity of the determined MMP, hence improve the reliability.
Process Design Aspects for Taking CO2 Enhanced Oil Recovery Offshore
Authors: Salim Mohammed , Harley John , Faizal Zairin 
Published: April 2012

Abstract
This paper presents the results of study work Granherne recently performed for an offshore carbon dioxide (CO2) Enhanced Oil Recovery (EOR) Project in the North Sea. In particular process design complexities are discussed for a new topside module comprising oil/gas separation, associated gas compression, dehydration with dense phase gas streams rich in CO2.
The importance of thermodynamic Equation of State (EOS) selection is highlighted, specifically for compressors and pumps in dense phase CO2 service. The selected HYSYS EOS results were benchmarked against a highly reliable Reference Fluid Thermodynamic and Transport Properties (REFPROP) database developed by National Institute of Standards and Technology (NIST). The comparisons are presented for compressibility, heat capacity, the heat capacity ratio and the enthalpy change across each compressor stage.
For the design of the gas dehydration unit, the experimental water equilibrium concentrations are compared with those predicted by commercially available simulators for a CO2-Water system. The HYSYS EOS did not model the acid gas-water system as accurately as Aqualibrium. The degasser flows for specifying the capacity of the LP Compression Train were under predicted by HYSYS EOS. The accuracy was improved by using the proprietary NRTL-SRK-Henry’s Law model in ASPEN PLUS.
The CO2 venting and depressurisation philosophy developed to avoid the formation of solid CO2 in the distribution headers is outlined. Also, the environmental aspects of CO2 rich gas cold venting versus flaring with assist gas is discussed.
The paper further highlights the technical design complexities compared to onshore CO2 EOR.
Alkaline Surfactant Polymer Flooding To Revitalize Oil Production from a Mature Water Flooded Field
Authors: Ansarizadeh M. M. , Weatherstone P. M. , Strong J. B. 
Published: April 2012

Abstract
Mitigating production decline is a challenging task that every oil company will be faced with at some point over the life of an oil reservoir. However, depending on the existing reservoir fluid and rock characteristics, saturation distribution, and the level of heterogeneity of the reservoir rock, Enhanced Oil Recovery (EOR) programs can be implemented to alleviate the decline in oil rate and improve overall recovery.
This paper presents an example of a how a mature waterflooded field in southwestern Saskatchewan, Canada could be revitalized using Alkaline-Surfactant-Polymer (ASP) flooding. In this study, laboratory tests were undertaken to select effective chemicals and optimize concentrations that would yield the highest potential oil recovery. Subsequent radial coreflood experiments demonstrated a wide range of potential recovery that depended on slug size and chemical concentration. A detailed numerical simulation of the optimum core displacement was performed in order to calibrate the interaction of the EOR agent with the reservoir rock and fluids, and ultimately upscaled to the full field numerical model Reservoir simulation sensitivity runs were conducted in order to identify an optimum field development strategy using the selected ASP fluid. The results from this optimized development strategy were compared to the waterflood base case to demonstrate the potential upside of the chemical flood. This paper also presents a holistic roadmap for developing EOR projects from initial concept to field implementation and beyond.
PDOs EOR Screening Methodology for Heavy-Oil Fractured Carbonate Fields - A Case Study
Authors: Warrlich Georg , Al-Waili Ibrahim , Said Dhiya , Diri Mohamed , Al-Bulushi Nabil , Strauss Jonathan , Al-Kindi Mohammed , Al-Hadhrami Fahad , van Heel Ton , van Wunnik John , de Zwart Bert-Rik , Blom Carl , Al-Mjeni Rifaat , Boerrigter Paul 
Published: April 2012

Abstract
Petroleum Development Oman’s (PDO) portfolio of heavy-oil, fractured carbonate prospects and fields contains a potentially large number of EOR opportunities, many of which present unique subsurface challenges. In the context of evaluating one such field, an EOR screening approach was developed combining subsurface definition through a tailor-made appraisal campaign, coupled with technical & economic feasibility evaluation of candidate EOR methods and benchmarking against other fields globally. This paper presents the screening workflow that will serve as template for the evaluation of future EOR opportunities in heavy-oil, fractured carbonate discoveries in PDO.
At the outset of the reservoir characterization of this field it was recognized that the application of any EOR technique would be challenging. High oil viscosities coupled with shallow depths render it a candidate for thermal EOR and potentially chemical concepts. However, key uncertainties in basic subsurface parameters such as reservoir architecture, matrix permeability, fracture spacing and (low) oil saturations, necessitated further data gathering before feasibility of any recovery mechanism could be concluded.
Based on literature surveys and examination of showstopper properties, a first-pass screening of a multitude of thermal and chemical EOR methods was conducted. A probabilistic assessment of key subsurface parameters was conducted against which the candidate EOR techniques were ranked. This resulted in the identification of SAGOGD, CSS, ISC and novel-chemical flooding as the most promising EOR methods.
For each of these methods the critical subsurface parameters and their impact were further assessed through the combination of (1) an appraisal campaign that included drilling of new wells, conventional production & pressure interference testing to constrain the uncertainties in these parameters and (2) Fit-for-purpose modeling (analytical analysis, sector modeling and full-field simulation) to check project feasibility.
It was found that none of the thermal recovery methods are technically or economically feasible, but chemical methods are being investigated further.
Investigating Low Salinity Waterflooding Recovery Mechanisms in Carbonate Reservoirs
Authors: Aladasani Ahmad , Bai Baojun , Wu Yu-Shu 
Published: April 2012

Abstract
Manipulating the injected brine composition can favorably alter the reservoir wetting state; this hypothesis has been validated in sandstone reservoirs by several scientists. A total of214 coreflooding experiments were conducted to evaluate low salinity waterflooding (LSWF) secondary recovery and 188 experiments were conducted to evaluate tertiary recovery, for sandstone reservoirs. Although the incremental recovery potential in carbonate reservoirs is greater than in sandstones, only a few imbibition and coreflooding experiments have been conducted. The simulator and recovery mechanisms presented by Aladasani et al. (2012) are used and their suitability and validity to low salinity waterflooding in carbonate reservoirs has been confirmed. This has been achieved by comparing simulated LSWF secondary and tertiary recoveries with published coreflooding experiments. Furthermore, the prediction profiler in JMP was used to examine incremental recovery for the following variables: (a) acid number and interfacial tension (IFT) sensitivities, and (b) 2nd stage injected brine and 3rd stage injected brine anion contents. In weak water-wet conditions, the incremental recovery is driven by low capillary pressures, and the underlining recovery mechanism is the increase in oil relative permeability. Therefore, wettability modification is ideal when achieved by shifting the wetting state from oil-wet or water-wet to a maintained intermediate wetting condition irrespective of the injected brine salinity dilution. If the wettability is shifted to a strong water-wet system, then it would be more favorable to use brine with anions to shift the wettability back to an intermediate wetting state. IFT has a bigger impact on LSWF in carbonate reservoirs; however, contact angle is more significant to the final oil recovery. Future work should consider studying the impact of cationic and anionic ions on coreflooding recovery separately and using cores with different initial wetting states, preferably strong oil-wet cores.