bluuebunny/crossref_metadata_2025 huggingface dataset:
An Overview of Conformance Control Efforts for the West Sak Field on the North Slope of Alaska
Authors: Peirce J. W. , Hutcherson M. R. , Jensen M. D. , Brice B. W. , Vasquez J. E. , Woods A.
Published: June 2014

This paper presents a field case study of conformance engineering efforts completed in the West Sak field throughout the past eight years. The West Sak field is a shallow viscous oil reservoir with poorly consolidated sand that has been under waterflood since 1998. Because of the nature of the formation and the completion techniques used, the field has experienced some severe conformance issues. Conformance candidate identification and selection criteria are reviewed followed by an overview of additional problem characterization efforts. A variety of solution designs considered and attempted are discussed with a summary of lessons learned from both failures and successes during this effort. This review discusses treatments that range from pumping graded CaCO3, molten wax, special cement blends, and, finally, preformed particle gels (PPGs) or water swelling polymer (WSP) crystals. A majority of these treatments were executed on horizontal wells, which required adjustments for some challenging placement control dynamics. A review of the efforts to control those placement dynamics is presented, discussing some potential problems associated with that control. The principle objective of this work was the elimination of open channels connecting water injection wells with oil producers. This connection eliminated matrix flow between the wells and threatened secondary recovery potential. Ultimately, the evolution of current solution treatments is provided with a brief benefit summary of the overall performance of this effort.
Minimum Miscibility Pressure Studies in the Bakken
Authors: Adekunle Olawale , Hoffman B. Todd
Published: June 2014

The Bakken is among the shale reservoirs which have been discovered to hold a vast amount of oil resource contributing to the production boom in the US. This unconventional reservoir, like most others, displays favorable initial production rates due to stimulation by hydraulic fracturing, but production rates quickly decline after few months. Due to the extremely low permeability and low recovery factors, miscible gas injection is considered for improving the recovery of oil in the Bakken formation. Feasibility of miscible gas injection in the Bakken depends on the analysis of minimum miscibility pressure (MMP) experiments.

The Rising Bubble Apparatus (RBA) has been chosen for the purpose of these experiments. The RBA provides results in a short amount of time using small amounts of fluid samples. The RBA consists of a cell gage containing a flat glass tube where oil samples are placed and an injection needle where gas is injected into the flat glass tube. To simulate reservoir conditions, the glass tube is pressurized using de-ionized water and heating plates surrounding the cell are used to regulate temperature. Visual observation of the injected gas bubble behavior is captured by a camera as it rises and moves upward along the oil column. The MMP occurs when the gas bubble dissolves into the oil before reaching the top of the oil column.

MMP results from a Bakken crude sample show a range from 2340 to 3000 psia at a temperature of 215 °F using CO2 as the injection fluid. Other injection fluids such as nitrogen and hydrocarbon gases have been tested and provided MMP values from 3500 to over 5000 psia depending on the gas. MMP results from Bakken crude oil samples were compared to existing correlations and more correlations were found to produce unreliable MMP results. Further comparison using an equation of state phase-behavior program has shown similar results with the RBA MMP results.

The impact of different injection fluids, inclusive of CO2 and enriched hydrocarbon gases is the subject of this study. MMP results are influenced by the choice of injection fluids, providing valuable information for economic production and increased recovery in the Bakken formation. The results from this study provide MMP data for a range of injection fluids that can be used in planning pilot tests for miscible gas injection in the Bakken.
Crude Oil/Brine Interactions and Spontaneous Formation of Micro-Dispersions in Low Salinity Water Injection
Authors: Mahzari Pedram , Sohrabi Mehran
Published: June 2014

Low salinity water injection (LSW) has recently attracted much attention as a technique for improving oil recovery. Several mechanisms have been put forward for oil recovery by LSW, however, their contribution to the observed additional oil recovery has not been well established and currently a consistent mechanism that can adequately explain both successful and unsuccessful results of LSW is lacking. Most of the proposed mechanisms attribute the low salinity effects to wettability alteration towards more water-wet conditions. This has resulted in many studies of LSW being mainly focused on the role of rock and its constituents whereas the role of fluid/fluid interactions has been largely ignored. We have recently reported the results of a series of direct flow visualization of LSW, which have revealed spontaneous formation of micro-dispersions of water in oil when a crude oil comes in contact with low salinity brines (Emadi and Sohrabi 2013).

In the current work, we further investigated interactions between crude oil and brine by performing a series of fluid characterization tests. Five different crude oil samples were used to individually bring them in contact with brines with various salinity levels to identify experimentally subtle changes in the oil composition. The process of contacting the crude oils and brines was designed and performed very carefully to avoid physical agitation between the two phases in order to replicate reservoir flow conditions. Then, samples of the oil were taken for qualitative and quantitative analysis including ESEM, FTIR, and Karl Fischer Titration. The results demonstrate spontaneous formation of water-in-oil dispersions when salinity of the brine is reduced to below 2000 ppm. This phenomenon is associated with detectable changes in oil composition, which occurred consistently in the tested crude oils. Our quantitative analysis shows that the concentration of micro-dispersions varies depending on the SARA content of the oil and there is a brine salinity threshold at which microdispersion concentration in the oil changes sharply. These new findings coupled with our micromodel visualizations (Emadi & Sohrabi 2013) reveal some new aspects of LSW and may lead to the development of relatively simple screening tests to identify suitability of a crude oil for LSW.
A Successful Story Of An Integrated Geologic And Reservoir Engineering Approach Of The Gandu Unit
Authors: Yaguaracuto Alfredo , Bowser Peter , Sands Ken , Gamez Amy , Keiser Leslie
Published: June 2014

This paper presents the success story of an integrated approach to optimize the production performance of the Goldsmith Andector Unit (Gandu) in West Texas. All production is from the Clearfork formation, a typical carbonate reservoir characterized by large and discontinuous pay intervals with low reservoir energy and high residual oil saturation. Re-development of this mature field began as a 20-acre infill drilling program in 2001 and has been under waterflood expansion since 2008.

A multi-disciplinary team was commissioned to improve production in Gandu. The team used an aggressive approach towards development practices of all aspects including reservoir engineering, geologic, and operational practices. Reservoir characterization and numerical simulation work in conjunction with classical methods validated the 650 MMSTB of original oil in place (OOIP) and the 64 MMSTB estimated waterflood reserves in the reservoir. The team focused on optimizing the base production, monitoring well performance, and identifying opportunities to increase production through workovers, returning-to-production (RTP) jobs and recompletions.

This paper details the systematic approach that was followed in order to achieve waterflood expansion success including geological characterization, reservoir engineering, data acquisition, production monitoring, well automation, field optimization, and program development for subsequent years. Details of the workflow implemented under the technical approach, best operational practices, and lessons learned are discussed.

As a result, the production of the field increased approximately 70%, with a total increase of 2,800 BOEPD by 2009. The field continues to produce significantly more than it did prior to the waterflood expansion in 2008.
Data Analysis and Novel Screening Criteria for Polymer Flooding Based on a Comprehensive Database
Authors: Saleh Laila Dao , Wei Mingzhen , Bai Baojun
Published: June 2014

Screening is considered the first step in evaluating potential enhanced oil recovery (EOR) techniques for candidate reservoirs; therefore, it is important to update the screening criteria as new technologies are developed. However, most recently published screening criteria regarding polymer flooding were based on data collected from the bi-annual EOR surveys published by the Oil & Gas Journal. These data recorded valuable information for finished and ongoing polymer flooding worldwide, but they are constrained in two ways. Firstly, they do not include some important information, such as the formation water salinity, divalent concentration, and polymer type and concentration. Secondly, the field data do not reflect recent polymer technology developments that are still in the laboratory evaluation and pilot testing stages. To overcome these limitations, a comprehensive dataset that provides the overall picture of polymer flooding research and application is presented in this paper. A total of 865 polymer flooding projects were considered to construct the dataset, including 481 field projects from the Oil & Gas Journal (1974-2012), 329 laboratory experiments (1964-2013), and 55 pilot test projects (1966-2011) recorded in the literature. After enhancing the data quality, graphical and statistical methods were used to analyze and describe the dataset. The distribution of major parameters important to polymer flooding design is presented using histograms, and the range of all parameters and their statistical values are presented using box plots. New screening criteria are presented based on these statistics of the defined parameters. Compared to published screening analyses, the new dataset and criteria provide more information critical to the design of a successful polymer flooding project, such as data pertaining to the formation water salinity, polymer molecular weight and concentration, polymer viscosity, and slug size.
Effects of Hardness and Cosurfactant on Phase Behavior of Alcohol-Free Alkyl Propoxylated Sulfate Systems
Authors: Puerto Maura C. , Hirasaki George J. , Miller Clarence A. , Reznik Carmen , Dubey Sheila , Barnes Julian R. , vanKuijk Sjoerd
Published: June 2014

The effect of hardness was investigated on equilibrium phase behavior in the absence of alcohol for blends of three Alcohol Propoxy Sulfates with an internal Olefin Sulfonate having C15-18 chain length. Hard brines investigated were synthetic Sea Water, 2*SW, and 3*SW, the last two having double and triple the total ionic content of SW with all ions present in the same relative proportions as in SW. Optimal blends of the APS/IOS systems formed microemulsions with n-octane having high solubilization suitable for EOR at both ~25°C and 50°C. However, oil-free aqueous solutions of the optimal blends in 2*SW and 3*SW, as well as in 8 wt% and 12 wt% NaCl solutions with similar ionic strengths, exhibited cloudiness and/or precipitation and were unsuitable for injection. In SW at 25°C the aqueous solution of the optimal blend of branched alcohol C16,17 7PO sulfate and IOS15-18 was clear and suitable for injection. A salinity map prepared for blends of these surfactants illustrates how such maps facilitate selection of injection compositions where injection and reservoir salinities differ. The same APS was blended with other APSs and Alcohol Ethoxy Sulfates in SW at ~25°C, yielding microemulsions with high n-octane solubilization and clear aqueous solutions at optimal conditions. Two APS/AES blends were found to form suitable microemulsions in SW with a crude oil at its reservoir temperature near 50°C. Optimal conditions were nearly the same for hard brines and NaCl solutions with similar ionic strengths between SW and 3*SW. Although the aqueous solutions for the optimal blends with crude oil were slightly cloudy, small changes in blend ratio led to formation of lower phase microemulsions with clear aqueous solutions. When injection and reservoir brines differ, it may be preferable to inject at such slightly underoptimum conditions to avoid encountering upper phase conditions produced by inevitable mixing of injected and formation brine.
Compositional Surveillance Program for Assessing Prudhoe Bay Vaporization Process
Authors: Jhaveri Bharat , Steen Becky , Connolly Michael
Published: June 2014

Prudhoe Bay field, the largest oil and gas accumulation in North America, has a large gas cap in communication with the oil rim. In addition to the liquid condensate held in the gas phase, the original gas cap contains relict oil that exists in the liquid phase at low saturations and is remnant of the oil migration - spill history of the reservoir. One of the key recovery mechanisms at the Prudhoe Bay field is the use of lean gas injection to increase recovery through vaporization of relict oil and dropped-out condensate in the original gas cap, and residual oil in the expanded gas cap. The lean gas vaporization project was implemented with an initial installed gas handling capacity of 2 BCF/D which was successively expanded to 8 BCF/D in several Gas Handling eXpansion (GHX) projects making it the largest hydrocarbon gas injection project in the world. After processing the produced gas to manufacture NGLs and Miscible Injectant, the lean gas is reinjected into the Prudhoe Bay gas cap for pressure support and vaporization of liquid phase hydrocarbons. In addition to estimates of black oil benefits, design and commercial evaluation of each stage of the gas handling expansion required accurate prediction of vaporization benefits from lean gas injection.

A compositional surveillance program was designed and implemented to assess the efficiency of the vaporization process in the field. This paper describes the surveillance program in which the routine separator tests conducted at the specified well locations for fluid allocation and production optimization are modified to include additional measurements of extended separator gas compositions and separator oil API gravity. The paper also presents details of an analytical procedure in which the measured compositional information from the well tests is used together with other relevant field data to deduce the effectiveness of the vaporization process. The compositional surveillance data analysis procedure is demonstrated by application to the gravity drainage area of the Prudhoe Bay field. Deliberate application of the compositional surveillance data acquisition and analysis by the Prudhoe Bay Reservoir Management team will significantly impact the optimization of the vaporization process in the field.
Geochemical Interpretation of Low Salinity Water Injection in Carbonate Oil Reservoirs
Authors: Al-Shalabi Emad W. , Sepehrnoori Kamy , Pope Gary
Published: June 2014

The advantages of using the low salinity water injection (LSWI) technique to improve oil recovery in carbonates have been reported in the literature; however, the mechanism behind it is still uncertain. In this paper, a geochemical/thermodynamic interpretation of the mechanism controlling oil recovery in carbonates by LSWI is proposed based on a recently published experimental study. The geochemical modeling was performed using two geochemical simulators (UTCHEM and PHREEQC). For the carbonate case considered in this paper, it was found that the wettability alteration was caused mainly by changing the surface charge of the rock rather than by dissolution. The findings cannot be generalized as the LSWI technique is case dependent.
Taking CO2 Enhanced Oil Recovery to the Offshore Gulf of Mexico
Authors: DiPietro Phil , Kuuskraa Vello , Malone Taylor
Published: June 2014

This paper evaluates the recoverable crude oil resource associated with applying carbon dioxide enhanced oil recovery (CO2 EOR) to reservoirs in the offshore Gulf of Mexico (GOM). Using data maintained by the Bureau of Ocean Energy Management (BOEM), a database containing 531 oil fields with a total original oil in-place (OOIP) of 69 billion barrels was used for the study. A total of 391 fields, representing 35% of the OOIP, were screened out at as not amenable to CO2 EOR based on size, residual oil saturation, and/or well-spacing. For the remaining 140 oil fields (containing 696 reservoirs), the data elements required to model a CO2 EOR flood, such as sweep efficiency and heterogeneity, were derived using a variety of methods. Crude oil production and CO2 demand profiles were produced from stream-tube finite-difference simulations for each oil-bearing reservoir. The study assumes that groups of proximate fields will be served by an anchor CO2 supply pipeline (one billion scf per year CO2) at a levelized transportation cost of $1.06/MscfCO2 (equivalently 20$/mtCO2). The economic determinations are based on a crude oil price of $90/bbl, CO2 price of $1.59/Mscf (30 $/MtCO2) at the capture facility plant gate, 18.75% royalty, and a 20% rate of return before taxes. BOEM projects that 182 billion barrels of OOIP remain undiscovered, two and a half times the discovered resource. Data from the analysis of discovered oil fields was used to estimate the expected CO2 EOR oil recovery from the undiscovered oil fields. Under the current CO2 EOR Technology scenario, the economically recoverable resources (ERR) is 0.8 billion barrels, a small fraction of the technically recoverable resource (TRR) of 23.5 billion barrels. The average efficiency of CO2 use in the ERR oil fields is estimated to be 7.2 Mscf/bbl and the associated demand for CO2 supply is 5.8 TCF. Under a scenario with Next Generation CO2 EOR performance, the ERR increases significantly to 14.9 billion barrels and 74 TCF of CO2 demand, consistent with an improved use efficiency of 5.0 MscfCO2/bbl.
Literature Review of Modeling Techniques for Foam Flow through Porous Media
Authors: Ma Kun , Ren Guangwei , Mateen Khalid , Morel Danielle , Cordelier Philippe
Published: June 2014

Foam, a dispersion of gas in liquid, has been investigated as a tool for gas mobility and conformance control in porous media for a variety of applications since late 1950s. These applications include enhanced oil recovery, matrix acidization treatments, gas leakage prevention, as well as contaminated aquifer remediation. In order to understand the complex physics of foam in porous media and to implement foam processes in a more controllable way, various foam modeling techniques have been developed in the past three decades.

This paper reviews modeling approaches obtained from different publications for describing foam flow through porous media. Specifically, we tabulate models based on their respective characteristics, including empirical and semi-empirical as well as mechanistic population-balance foam models. In various population-balance models, how foam texture is obtained and how gas mobility is altered as a function of foam texture, among other variables, are presented and compared. It is generally understood that both the gas relative permeability and viscosity vary in the reduction of gas mobility through foam generation in porous media. However, as the two parameters appear together in the Darcy's equation, different approaches have been taken to alter the mobility in the various models: only reduction of gas relative permeability, increasing of effective gas viscosity, or a combination of both. The applicability and limitations of each approach are discussed. How various foam generation mechanisms play a role in the foam generation function in mechanistic models is also discussed in this review, which is indispensable to reconcile the findings from different publications. Additionally, other foam modeling methods, such as the approaches using the fractional flow theory and those using the percolation theory, are also reviewed in this work. Several challenges for foam modeling, including model selection and enhancement, fitting parameters to data, modeling oil effect on foam behavior, and upscaling of foam models are also discussed at the end of this paper.
Preformed Particle Gel Extrusion through Open Conduits during Conformance Control Treatments
Authors: Imqam Abdulmohsin , Bai Baojun , Al Ramadan Mustafa , Wei Mingzhen , Delshad Mojdeh , Sepehrnoori Kamy
Published: June 2014

Millimeter-sized (10 um~mm) preformed particle gels (PPGs) have been used successfully as conformance control agents in more than 5,000 wells. They help to control both water and CO2 production through high-permeability streaks or conduits (large pore openings), which naturally exist or are aggravated either by mineral solutions or by a high injection pressure during the flooding process. This paper explores several factors that can have an important impact on the injectivity and plugging efficiency of PPGs in these conduits. Extensive experiments were conducted to examine the effect of the conduit's opening size and the PPG strength on the ratio of the particle size to the opening diameter, injectivity index, resistance factor, and plugging efficiency. Five-foot tubes with four internal diameters were designed to emulate the opening conduits. Three pressure taps were mounted along the tubes to monitor PPG transport and plugging performance. The results show that weak gel has less injection pressure at a large particle opening ratio compared to strong gel. PPG strength impacted injectivity more significantly than did particle opening ratio. Resistance factor increased as the brine concentration and conduit opening size increased. PPGs can significantly reduce the permeability of an open conduit and their plugging efficiency depends highly on the particle strength and the conduit's opening size. The particle size of PPG was reduced during their transport through conduits. Experimental results confirm that the size reduction was caused by both dehydration and breakdown. Based on the lab data, two mathematical models were developed to quantitatively calculate the resistance factor and the stable injection pressure as a function of the particle strength, particle opening ratio, and shear rate. This research provides significant insight into designing better millimeter-sized particle gel treatments intended for use in large openings, including open fractures, caves, worm holes, and conduits.
New Water Soluble Anionic NVP Acrylamide Terpolymers for Use in Harsh EOR Conditions
Authors: Gaillard N. , Giovannetti B. , Favero C. , Caritey J.-P. , Dupuis G. , Zaitoun A.
Published: June 2014

Water soluble anionic polymers are widely used as Mobility Control agents in EOR. However, their shear, salt, free radical and thermal stability limit their domain of application. A joint industrial effort has led to new optimized polymer compositions. The chemical structure has been designed to improve long term thermal and salt stability. The functional groups on the polymer chain are acrylamide (AM), sodium acrylate (AA), sodium acrylamido-tertiary-butyl sulfonate (ATBS) and N-vinyl pyrrolidone (NVP). The composition of the different groups was varied to produce different polymer prototypes. The bulk gel polymerization process used to produce at industrial scale EOR polymers has been fine-tuned using NMR structural analysis at different conversion rates. The best polymer candidates were submitted to stability tests. Thermal stability was investigated with residual oxygen between 0 and 200ppb at temperature up to 120°C and salinity up to 70 g/L TDS with high hardness. Results show that the joint presence of NVP and ATBS in specific amounts in the polymer structure improves thermal and salt stability. Some of the polymers, whose chemical structure was optimized to maximize stability, could withstand harsh reservoir conditions with little loss of viscosity for an aging time of at least 1 year. These species were then submitted to coreflood experiments and showed good propagation properties in a 100-150 mD carbonate rock. Results show that polymer flooding can be successful in reservoirs with high temperature and harsh salinity conditions. The thermal resistant polymers can be used for polymer, surfactant polymer floods and are promising for alkaline surfactant polymer systems as well. They may be beneficial to other oil and gas applications where heat and salt stability are needed. With this technology, polymer viscosity is stable while it propagates through the reservoir and a favorable mobility ratio is maintained from injectors to producers.
Optic imaging of Oil/Water flow behavior in nano-scale channels
Authors: Liu Songyuan , Wu Qihua , Bai Baojun , Ma Yinfa , Wei Mingzhen , Yin Xiaolong , Neeves Keith
Published: June 2014

Unconventional oil reservoir has presented the potential to become a significant source of hydrocarbon in the future productions. Many shale oil systems consist of nano-scale pores and micro-scale fractures that are significantly smaller than those from conventional reservoirs. Such small size of the pore throats in shale may differ from the size of the saturating fluid molecules by only slightly more than one order of magnitude. This difference will result in different wettability, fluid flow mechanisms and storage capabilities in unconventional shale oil systems. However, the fluid flow behavior in the micro-scale or even nano-scale pores and channels is poorly investigated and understood. Therefore, it is increasingly important to investigate fluid flow behaviors and the fluids residue saturation in the nano-scale channels. In this work, a lab-on-chip approach for direct visualization of the water/oil flow in nano-scale channels is developed by using advanced confocal microscopy system combined with nano-fluidic chip. A comprehensive study of water/oil flow behaviors is presented. During drainage process, liquids tend to be piston like flow under micro; both residual phase saturation and configuration affect the flow behavior under smaller scale. During imbibition process, a fading out phenomenon was observed which. For residual phase saturation, confocal system can give a precise description within 3-dimensional scale.
Development of a Multi-Continuum Multi-Component Model for Enhanced Gas Recovery and CO2 Storage in Fractured Shale Gas Reservoirs
Authors: Jiang Jiamin , Shao Yuanyuan , Younis Rami M.
Published: June 2014

Shale gas reservoirs have been proposed as feasible choices of location for injection of CO2 and/or N2 because this method could enhance recovery of natural gas resources, while at the same time sequester CO2 underground. In this paper, a fully coupled multi-continuum multi-component simulator which incorporates several transport/storage mechanisms is developed. To accurately capture physics behind the transport process in shale nanopores, Kundsen diffusion and gas slippage are included in the flow model. An extended Langmuir isotherm is used to describe the adsorption/desorption behavior of different gas components and the displacement process of methane as free gas. Pressure-dependent permeability (due to rock deformation) of natural fractures induced by hydraulic fracturing is also considered in the simulator.

In addition, modeling of complex fracture networks is very crucial for simulating production of shale gas reservoirs because there exists various scales of fractures with multiple orientations after the fracturing treatment for horizontal well. In this work, a hierarchical approach which integrates EDFM with dual-continuum concept is adopted. The hybrid model includes three domains: matrix, major hydraulic fractures and large-scale natural fractures (described by EDFM), and micro-fractures in SRV region which are modeled by dual-continuum approach. Embedded Discrete Fractures Model (EDFM) is an efficient approach for explicitly simulating large-scale fractures in Cartesian grid instead of complicated unstructured grid. Moreover, a nested-grid refinement method is used to capture the fluids transfer from matrix to fractures.

Fully implicit scheme is applied for discretizing fluid equations, and the corresponding Jacobian matrix is evaluated by Automatic Differentiation with Expression Templates Library (ADETL). The AD-Library framework allows wide flexibility in the choice of variable sets and provides generic representations of discretized expressions for gridblocks. Several simulations and sensitivity analysis are performed with the developed research code for determining the key factors affecting shale gas recovery. Modeling studies indicate that the properties of fracture networks could greatly influence methane production. Different injection strategies including huff-n-puff scenario are also evaluated to provide insights for optimizing production of multi-fractured horizontal well. Results show that CO2/N2 injection can be an effective approach with great application potential for enhancing shale gas recovery.
Coupled Geochemical-Based Modeling of Low Salinity Waterflooding
Authors: Nia Korrani Aboulghasem Kazemi , Jerauld Gary R. , Sepehrnoori Kamy
Published: June 2014

Low salinity waterflooding is an emerging EOR technique in which the salinity of the injected water is substantially reduced to improve oil recovery over conventional higher salinity waterflooding. Although there are many low salinity experimental results reported in the literature, publications on modeling this process are rare. While there remains some debate about the mechanisms of LoSal®1 EOR, the geochemical reactions that control the wetting of crude oil on the rock are likely to be central to a detailed description of the process. Since no comprehensive geochemical-based modeling has been applied in this area, it was decided to couple a state-of-the-art geochemical package, IPhreeqc, developed by the United States Geological Survey (USGS) with UTCOMP, the compositional reservoir simulator developed by The University of Texas at Austin.

A step-by-step algorithm is presented for integrating IPhreeqc with UTCOMP. Through this coupling, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, and ion-exchange reactions under non-isothermal, non-isobaric and both local-equilibrium (away from the wellbore) and kinetic (near wellbore) conditions. Consistent with the literature, there are significant effects of water-soluble hydrocarbon components (e.g., CO2, CH4, and acidic/basic components of the crude) on buffering the aqueous pH and more generally, on the crude oil, brine, and rock reactions. Thermodynamic constrains are used to explicitly include the effect of these water-soluble hydrocarbon components. Hence, this combines the geochemical power of IPhreeqc with the important aspects of hydrocarbon flow and compositional effects to produce a robust, flexible, and accurate integrated tool capable of including the reactions needed to mechanistically model low salinity waterflooding.

Different geochemical-based approaches to modeling wettability change in sandstones (e.g., interpolation based on total ionic strength and Multicomponent Ion Exchange through surface complexation of the organometallic components) were implemented in UTCOMP-IPhreeqc and the integrated tool is then used to match and interpret a low salinity experiment published by Kozaki (2012) and the field trial done by BP at the Endicott field.
Impact of Surfactant Structure and Oil Saturation on the Behavior of Dense CO2 Foams in Porous Media
Authors: CHABERT Max , NABZAR Lahcen , BEUNAT Virginie , LACOMBE Emie , CUENCA Amandine
Published: June 2014

Miscibility with oil lies among the main advantages of dense CO2 injection for pore scale oil displacement during tertiary recovery. At reservoir scale, injecting dense CO2 in the form of foam can also improve its sweep efficiency. However, although the use of such miscible dense CO2 foams has been considered in over twenty pilots since the 1980's, only few lab studies have considered foams formed with CO2 in this particular thermodynamical state. Indeed, dense CO2 has solvation properties and a viscosity higher than that of a gas. This impacts several attributes of its foams in porous media, such as Mobility Reduction Factors (MRF) and behavior in presence of oil.

We present new results demonstrating that classical foamers are not effective in improving mobility control of dense CO2, but that relatively high MRF are achieved using carefully formulated surfactants. Based on these findings, we study the impact of foam on miscible flooding efficiency in corefloods. Reversely, we also evaluate how miscibility of CO2 with oil impacts foam MRF. Our approach is based on multiple corefloods experiments, with different formulations, at various oil saturations. Additionally, physical-chemistry measurements such as interfacial tension estimations and foam stability monitoring are performed in reservoir conditions (pressure and temperature). This set of experiments shows that a balance must be found between maximizing MRF and minimizing the risk of emulsion formation in porous media.

This paper brings new insights on the interpretation of CO2 foams coreflood results, based on the thermodynamical properties of the CO2 phase. It provides the reader with a clearer view of gas properties that must be considered when analyzing results of dense CO2 foams corefloods. This can help reconcile seemingly contradictory results appearing in the literature, particularly regarding the values of MRF as a function of pressure and in the presence of oil.
Aspects of Modeling Asphaltene Deposition in a Compositional Coupled Wellbore/Reservoir Simulator
Authors: Darabi Hamed , Shirdel Mahdy , Kalaei M. Hosein , Sepehrnoori Kamy
Published: June 2014

Asphaltene precipitation, flocculation, and deposition in the reservoir and producing wells cause serious damages to the production equipment and possible failure to develop the reservoirs. From the field production prospective, predicting asphaltene precipitation, flocculation, and deposition in the reservoir and wellbore essentially avoids high expenditures associated with the reservoir remediation, well intervention techniques, and field production interruption. Since asphaltene precipitation and deposition strongly depend on the pressure, temperature, and composition variations (e.g. phase instability due to CO2 injection), it is important to have a model that can track the fluid behavior during the entire production process from the injection well to the production well, which is absent in the literature.

In this paper, a comprehensive thermal compositional coupled wellbore/reservoir simulator with a capability of modeling asphaltene phase behavior in the reservoir and the wellbores is presented to address the wellbore/reservoir interaction, the effect of asphaltene deposition on the flow prediction and long-term reservoir performance. Indeed, the simulator models multiphase fluid flow in the reservoir and the wellbore to enable comprehensive production system analysis. In addition, wettability alteration due to the asphaltene deposition on the rock surface is considered in our models.

We present primary production and CO2 flood simulation cases to investigate the effect of asphaltene deposition on oil recovery. The results show that injection of the light components into the reservoir significantly increases the instability of asphaltene components in the reservoir where they can precipitate further around the wellbore and in the wellbore. The precipitated asphaltene in the reservoir can be carried into the wellbore and be combined with excess asphaltene formation and deposit in the wellbore. In addition, our simulation shows that well productivity decreases significantly in case of asphaltene precipitation and deposition during the production life of a reservoir.
Modeling the Effects of Porous Media in Dry Gas and Liquid Rich Shale on Phase Behavior
Authors: Ma Yixin , Jamili Ahmad
Published: June 2014

Because of the confinement effects in shale formations, fluid flow is different compared to conventional reservoirs. The interactions between the fluid molecules and porous wall inside nanopores play such an important role that can change the phase behavior of the fluids. The fluids in shale reservoirs are usually stored in two forms, free fluids and adsorbed fluids. The region where free fluids are stored has negligible fluid-wall interactions while the region for adsorbed fluids is under strong pore wall influence. The current available equations of state cannot capture the phase behavior of the adsorbed phase in porous media due to the ignorance of the fluid-wall interactions. This paper discussed the effects of the fluid-wall interactions on fluid phase behavior from a modeling of of view.

The production from shale reservoirs in the US has shifted from gas windows to condensate windows and oil windows recently due to low natural gas price. Liquid-rich shales, such as Barnett, Eagle Ford, and Marcellus are brought more attentions than ever before. Thus, it is critical to understand the fluid phase behavior and properties and their impacts on production in the condensate systems. Our work focuses on the predictions of fluid critical property change and fluid density change inside nanoporous media. Simplified Local-Density theory for single component coupled with modified Peng-Robinson Equation of State was used to predict the density profiles of dry gas (pure methane) in confined pores. The model was then extended to mixtures for the study of condensate systems.

Our results showed that due to the fluid-wall interactions, the fluid density is not uniformly distributed across the pore. The fluid density is higher near the wall than that in the center region of the pore. It also showed that depending on fluid types, temperature, pressure and pore sizes, the fluid density profile would change. The pore size range we focused on was from 2 nm to 10 nm. In order to present the condensate system, a synthetic mixture of 75% methane and 25% n-butane is used. It is found that fluid composition is not uniform across the pore. Heavier component (n-butane) tends to accumulate near the wall while lighter component (methane) would like to stay in the center region of the pore. For a 10 nm wide pore, the composition of n-butane of the synthetic mixture can be as high as 66% close to the pore wall.
Enhancing Well Stimulation with Improved Salt Tolerant Surfactant for Bakken Formation
Authors: Zhou Jia , Cutler Jennifer , Hughes Baker , Morsy Samiha , Morse Aaron , Sun Hong , Qu Qi
Published: June 2014

The Bakken formation is located in parts of Montana, North Dakota, and Saskatchewan, Cananda. North Dakota alone produces more than 700,000 barrels per day and still growing, which accounts for 11 percent of the domestic total crude oil production, while the oil recovery factor of 1% in Bakken is necessary to be improved to a higher level. Current practice involves fracture stimulation of the mature Upper and Lower Bakken Shales above and below the middle layer (pay zone in carbonate or siltstone). The fractures penetrate and connect natural fractures within the reservoirs and promote more efficient drainage of the oil. This situation suggests that a surfactant technology incorporating in the well stimulation fluids at low dosage can be a fit in Bakken formation to enhance oil recovery. If properly designed, such additives in the fracture fluids will penetrate into the highly oil-saturated matrix or natural fracture region and accelerate the extraction of the oil in place by rapid imbibition. Extracted oil can readily flow from the matrix into the propped fracture system. Another benefit of this surfactant technology is its engineered property to leave the matrix or natural fracture face water-wet to facilitate oil movement during production.

This paper presents a study of a series of such stimulation fluid additives developed for enhanced oil recovery. Crude oil samples from the Bakken formation were analyzed for several properties pertinent to surfactant formulation including organic constituents, total acid number, and viscosity. Compatibility tests were carried out including surfactant/produced water interaction, emulsion tendency, and surfactant compatibility with proposed fracturing fluids. A spontaneous imbibition process was employed to mimic surfactant additives penetrating the tight matrix and microfractures to recover more hydrocarbons. The results show that more than one of these products improved recovery of Bakken crude oil by spontaneous imbibition. The best of these products is recommended for field application.
An Experimental Study of Cyclic CO2 Injection to Improve Shale Oil Recovery
Authors: Gamadi T. D. , Sheng J. J. , Soliman M. Y. , Menouar H. , Watson M. C. , Emadibaladehi H.
Published: June 2014

The low recovery and high oil volume remaining in shale oil reservoirs are a strong motivation to investigate the application of enhanced oil recovery methods in these reservoirs. This paper presents the potential of applying cyclic CO2 injection to improve the recovery factors of shale oil reservoirs. Cyclic CO2 injection could be an effective technique to improve the oil recovery of this type of reservoirs for several reasons. It is a single-well process; well-to-well connectivity is not required, the hydraulic and natural fractures provide a large contact area for the injected gas to penetrate and diffuse into the low-permeability matrix; and the payback period of the cyclic CO2 injection process is short compared with the other flooding process. Very limited numerical and laboratory studies are available to study the feasibility of CO2 huff-n-puff for shale oil reservoirs. Latest numerical studies have revealed that CO2 huff-n-puff technique could be an effective method to increase recovery factors of shale oil reservoirs. In order to support the numerical studies results, a laboratory study was conducted using shale cores from Mancos and Eagle Ford. The aim of this study is to evaluate the potential of cyclic CO2 injection. Many design parameters such as soaking period, soaking pressure, and numbers of cycles were considered to evaluate the feasibility of cyclic CO2 injection. The laboratory results indicate that cyclic CO2 injection improved recovery of shale oil cores from 33% to 85% depending on the shale core type and the other operating parameters. These results have shown that cyclic CO2 injection is a promising method to improve the recovery of shale oil reservoirs. Also this study aided to develop a better understanding of the performance of cyclic CO2 in shale oil reservoirs.
Validating Surfactant Performance in the Eagle Ford Shale: A Correlation between the Reservoir-on-a-Chip Approach and Enhanced Well Productivity
Authors: He Kai , Xu Liang , Gao Yuefeng , Neeves Keith B. , Yin Xiaolong , Bai Baojun , Ma Yinfa , Smith Jonathan
Published: June 2014

For liquids-rich shale plays, surfactants have proven to be a critical component in hydraulic fracturing fluid systems for enabling enhanced oil and gas recovery. The industry's most commonly used surfactant is a non-emulsifying surfactant (NES), but it has been previously demonstrated that a weakly emulsifying surfactant (WES) appears to be more efficient at mobilizing oil through tight pore throats. In this study, fundamental differences between those two surfactant types were further demonstrated using a Reservoir-on-a-Chip (ROC) approach, which allows direct visualization of oil recovery with the various surfactant fluids, allowing for the testing on both homogenous and heterogeneous pore structures with various geometries. The laboratory testing showed that, compared to a non-surfactant-bearing control fluid and the NES, the WES showed higher oil recovery efficiency at equal driving pressure.

As a result of the laboratory testing indications, a multiple well trial program was conducted in two separate areas of the Eagle Ford shale. Production data from the wells stimulated using a WES-bearing fracturing fluid were normalized in terms of lateral lengths and fracturing stages, and compared to the offset wells stimulated using a NES-bearing fracturing fluid. Early production results suggest that wells treated with the WES exhibited enhanced productivity compared to those treated with the NES.
Simulation of Surfactant Flooding in the Presence of Dissolved and Free Gas Accounting for the Dynamic Effect of Pressure and Oil Composition on Microemulsion Phase Behavior
Authors: Trouillaud Adrien , Patacchini Leonardo , de Loubens Romain , Moncorgé Arthur
Published: June 2014

The dynamic effect of pressure and Oil composition on Microemulsion phase behavior, complementing the key effect of variable salinity, has been implemented in our four-fluid-phase, fully implicit in-house research reservoir simulator. This has been achieved through self-consistent coupling of a traditional Gas/Oil/Water phase equilibrium model, either compositional or generalized black-oil,—providing phase fractions, oleic composition, and aqueous salinity—with a Microemulsion model based on oleic/aqueous/chemical pseudophase equilibrium.

As an application example and validation test case, we consider a hypothetical surfactant/polymer (SP) coreflood of a saturated Oil, interrupted by a progressive depressurization, during which dissolved gas is released, which shifts the Microemulsion phase state from Winsor Type III to Type II-. This proves the good functioning of our new option, and shows, yet on a simple case, that it does not degrade numerical performance, despite the introduction of additional nonlinear dependencies.