bluuebunny/crossref_metadata_2025 huggingface dataset:
Simulation of Coupled Hydraulic Fracturing Propagation and Gas Well Performance in Shale Gas Reservoirs
Authors: Wang Xu , Winterfeld Philip , Ma Xu , Ye Dengsheng , Miao Jijun , Wang Yonghong , Wang Cong , Wu Yu-Shu
Published: June 2014

Hydraulic fracturing combined with horizontal drilling has been the technology that makes it possible to economically produce natural gas from unconventional shale gas reservoirs. For best performance of fracturing stimulation, hydraulic fracturing designing parameters, such as different proppants, fracturing liquids, and injection rate and pressure, should be evaluated before the oeration in a particular reservoir system. Traditional evaluation and optimization approaches are usually based on the simulated fracture properties along, such as fracture areas. In our opinion, the better methodologyshould be also related to production data from the stimulated wells afterwards, because the enhanced production is the ultimate goal.

In this paper, we present a general fully-coupled numerical framework to simulate the hydraulic induced fracture propagation and post-fracture gas well performance. This three-dimensional, multi-phase simulator focuses on: (1) fracture width increase and fracture propagation that occurs as slurry is injected into the fracture, (2) erosion caused by fracture fluid and leakoff, (3) proppant subsidence and flowback, and (4) multi-phase fluid flow through various-scaled anisotropic natural and man-made fractures. Mathematical and numerical details on how to fully couple the fracture propagation part and the fluid flow part are discussed. Fracturing and production operation parameters, properties of the formation, and reservoir, fluid, and proppant properties are all taken into account in this model. The well may be horizontal, vertical, or deviated, as well as open-hole or cemented. This simulator is verified based on benchmarks the literature. We show its application by simulating the fracture network (hydraulic and natural fractures) propagation and production data history matching of field production data in China. We conduct a series of real-data modeling studies with different combinations of fracturing parameters and present the methodology to design fracturing operations with feedback of simulated production data. This unified model aids in the optimization of hydraulic fracturing design, operations, and production.
Strategic Delineation of a Tight Oil Play
Authors: Garibaldi Luis , Mathukutty Shibu , Cullick A. S.
Published: June 2014

This paper describes a comprehensive methodology to rank drilling locations in a very large, unconventional tight-oil area based on both surface and subsurface characteristics. A North American case study is presented.

Operators entering new prospect areas with little well control must make decisions on locating limited numbers of exploratory wells. Large prospect areas can be characterized by a variety of different mineral rights, surface-permitting obligations, uncertainties in geologic subsurface characteristics, complexity of topography, a variety of available infrastructures, potential operational issues, and environmental and regulatory challenges. The decision to appraise an acreage position is very complex and has a high level of risk.

One solution to rank and risk candidate drilling locations is a procedure that considers the most critical variables needed for appraisal. The variables are used to generate optimized drilling location scenarios under various uncertainties and constraints using a mathematical probabilistic-optimization procedure and a ‘scorecard’ of surface cultural characteristics.
Probabilistic Forecasting of Horizontal Well Performance in Unconventional Reservoirs Using Publicly-Available Completion Data
Authors: Voneiff G. , Sadeghi S. , Bastian P. , Wolters B. , Jochen J. , Chow B. , Chow K. , Gatens M.
Published: June 2014

In this paper, we present a methodology to predict the performance of horizontal gas wells in unconventional reservoirs using publicly available completion data. Our process combines public domain data with statistical analysis and probabilistic simulation methods to forecast well performance without a detailed reservoir characterization. We have tested our methodology using a 425-well dataset from the unconventional Montney resource play in British Columbia, Canada. We believe this workflow can be applied to other resource plays with similar data.

In our SPE Paper 167154 [1], we determined the sensitivity of production performance to completion parameters using multivariate regression analysis on the same 425-well dataset from the Montney formation. We found that the number of fracture stages and the number of perforation clusters per stage were the most influential predictors of well performance.

In this paper, we discuss how we combined the regression analysis results with probabilistic methods to predict well performance. The model converts the deterministic regression coefficients into probabilistic distributions to account for parameters not considered in the original regression analysis, including reservoir properties. The results of our study show that by using this model, we can match the range of actual well performance outcomes with a 95% confidence.

Considering the importance of shale gas resources to the North American energy supply and the difficulty of characterizing shale gas reservoirs, this methodology offers a distinct advantage by providing a predictive model for well performance without the need for a detailed reservoir characterization. This also could be a beneficial tool to use in scoping studies where high-level, rapid evaluation is required.
CO2-Based Enhanced Oil Recovery from Unconventional Reservoirs: A Case Study of the Bakken Formation
Authors: Liu G. , Sorensen J. A. , Braunberger J. R. , Klenner R. , Ge J. , Gorecki C. D. , Steadman E. N. , Harju J. A.
Published: June 2014

As one of the largest unconventional resources in the world, the Bakken petroleum system has approximately 7.4 billion barrels of recoverable oil as estimated by the U.S. Geological Survey in 2013. These resources lie in a 200,000-square-mile area in North America. However, primary recovery rates are low, typically 3%–5%. The use of carbon dioxide (CO2) as an injection fluid may reduce the hydrocarbon viscosities in the reservoir and allow additional trapped oil to be produced. Another benefit of CO2 injection is to mitigate climate change.

In this study, detailed petrophysical and geological field models focusing on the Middle and Lower Members of the Bakken Formation in the Bailey and Grenora areas of western North Dakota were developed based on field characterization, well log interpretation, and laboratory core analysis by scanning electron microscopy, ultraviolet fluorescence, and standard optical microscopy techniques. A fine-scale model with a pair of horizontal wells was extracted from the initial Bailey model to examine the potential effectiveness of CO2-based oil recovery techniques. Based on characterization results for the simulation investigation, two three-stage hydraulic fractures were incorporated into the model for CO2 injection and oil production wells, respectively, as well as the characterized oil properties such as swelling test and minimum miscibility pressure measurement from selected reservoirs. A total of four cases for simulation were designed to enhance oil recovery by CO2 injection. These cases were run on a single porosity–permeability model to test the basic concepts and later incorporate these results into a dual porosity–permeability model.

The results show that CO2 injection may play a significant role in increasing oil production. Results of this study indicate that production can be enhanced by 43% to 58% compared to cases without CO2 injection. Since a single-porosity, singlepermeability model was used, relative permeability curves that represent the fractures and matrix were both tested to determine the effects of this variable on the outcome. The results indicated that CO2 enhanced oil recovery (EOR) is very sensitive to the relative permeability, and that result varied over 100% between the cases. This case study for CO2 storage in the Bakken Formation provides a basic guideline to address CO2-based EOR. Specifically, the efforts provide modeling input for future investigations that could lead to the design and implementation of a possible pilot-scale field test.
Modification of the Transient Linear Flow Distance of Investigation Calculation for Use in Hydraulic Fracture Property Determination
Authors: Behmanesh H. , Tabatabaie S. H. , Heidari Sureshjani M. , Clarkson C. R.
Published: June 2014

Long-term transient linear flow of hydraulically-fractured vertical and horizontal wells completed in tight/shale gas wells has historically been analyzed using the square-root of time plot. Pseudovariables are typically used for compressible fluids to account for pressure-dependence of fluid properties. Recently, a corrected pseudotime has been introduced for this purpose, where the average pressure in the distance of investigation (DOI) is calculated using an appropriate material balance equation. Therefore, the distance of investigation calculation is critically important in the determination of the linear flow parameter (product of fracture half-length and square-root of permeability, xf√k) as well as in the calculation of contacted fluid-in-place. Until now, the DOI for transient linear flow has been determined empirically, and may not be accurate for all combinations of fluid properties and operating conditions.

In this work, we have developed analytically-based equations for transient linear flow DOI for different operating conditions. Two different approaches were used: the impulse respond concept, and transient/boundary-dominated flow intersection method. The performance of these approaches was tested by analyzing synthetic production data from a series of fine-grid numerical simulations. These simulation runs were set up to obtain accurate estimates of the linear flow parameter for different operating conditions.

The calculated linear flow parameters determined by using our new DOI formulations and the input values in the numerical simulation are in good agreement. Of the two new DOI calculation methods provided, the unit impulse method provides more accurate results.

Linear flow analysis based on the DOI calculations presented in this work is significantly improved over previous formulations.
Using Simplified Local Density/ Peng-Robinson Equation of State to Study the Effects of Confinement in Shale Formations on Phase Behavior
Authors: Ma Yixin , Jamili Ahmad
Published: June 2014

A large amount of hydrocarbon fluids in shale formations are stored within the organic matters where the pore sizes are in the order of nanometer scales. Inside these nanopores, the interactions between the fluid molecules and porous walls play such an important role that can change the phase behavior as well as transport mechanisms of the hydrocarbon fluids. For a shale gas reservoir, the natural gas in the reservoir is usually stored in two forms, free gas and adsorbed gas. The region where free gas is stored has negligible fluid-wall interactions while the region for adsorbed gas is under strong pore wall influence. The current available equations of state cannot capture the phase behavior of the adsorbed gas phase due to the ignorance of the fluid-wall interactions.

This work focuses on modifying the Peng-Robinson equation of state (PR-EOS) using the Simplified Local-Density (SLD) theory. From the modified PR-EOS, the fluid density at any arbitrary position inside the pore can be calculated using the local density approximation. A density profile for any particular hydrocarbon fluids can be obtained by calculating the local densities of the fluids at each discretized interval along the pore. From the density profile one can distinguish the regions of adsorbed phase, transition phase and bulk phase of the fluids. The thickness and averaged fluid densities for each phase can also be obtained from the model. Once the thickness of the absorbed phase is known, it is possible to determine whether adsorption is a single layer or multilayer.

Our preliminary results show that depending on fluid types, either a single layer or multilayer adsorption is presented in those nanometer pores near the pore wall. The pore size range we focused on was from 100 nm to 1 nm. Methane and n-Butane were considered as fluids. When the pore size gets smaller and smaller, the absorbed layers at opposite pore walls can be merged together and result in the absence of the bulk fluid phase in the center areas of the pores. In this case, all the fluids in the pore are under influence of the wall. Our results also indicate that the fluid-wall interactions can have a much larger impacts on light components (methane) rather than heavy components (n-butane). That is, the density of the adsorbed phase of methane is more than two times the free gas density of methane (bulk density), while the n-butane adsorbed density is only slightly higher than its bulk density. The model has also been validated with molecular simulations for accuracy approval.
Modeling the Influence of Pressure Depletion in Fracture Propagation and Quantifying the Impact of Asymmetric Fracture Wings in Ultimate Recovery
Authors: Mata D. , Cherian B. , Gonzales V. , Higgins-Borchardt S. , Han H.
Published: June 2014

In 2014, more than 30,000 wells will be drilled in different unconventional plays across the US. As drilling density increases, chances are these new wells will be located in the vicinity of a producing unit. When the new well is being completed, the pressure depletion around the producing well affects the principal stress regime, creating low stress compartments that attract the majority of the slurry injected. This condition has been studied in the past for vertical wells and results confirmed that the asymmetric propagation of the fracture wings leaves vast sections of the reservoir un-stimulated affecting well performance. This study uses a dataset from the Williston basin to evaluate the impact of this condition in modern horizontal completions. Pore pressure maps from single well models are used to build a multi-well geomechanical model, a numerical fracture simulator is used to understand fracture geometry and quantify wing asymmetry and a multi-well production model is created to estimate the impact in ultimate recovery. Finally, this paper concludes with a series of recommendations regarding completion design and production strategy that can reduce the severity of fracture asymmetry and increase EUR.
Probabilistic Estimate of Global Coalbed Methane Recoverable Resources
Authors: Dong Zhenzhen , Holditch Stephen A. , Ayers Walter B. , Lee W. John
Published: June 2014

Because today's oil and gas industry recognizes the value of coalbed methane (CBM) resources, CBM exploration and development activities, once uniquely North American, are now under way on a global scale. Many publications address technically recoverable resources (TRR) of CBM in small geographic areas. However, there is little publicly information about the magnitude of TRR for coalbed methane on a global scale. Uncertainty exists in geologic and engineering data and, consequently, in the results of calculations made with these data. The uncertainty of the problem begs for a probabilistic solution.

Our objective was to determine distribution of CBM TRR worldwide. To achieve this goal, we developed a computer program, called Unconventional Gas Resource Assessment System (UGRAS). The program integrates a Monte Carlo technique with an analytical reservoir simulator. The combination provides an excellent means to predict production profiles for a wide variety of reservoir characteristics and producing conditions. Using UGRAS, we established the probabilistic distribution of original gas-in-place (OGIP), TRR and recovery factor (RF) for selected coals in U.S. and derived a representative recovery factor distribution for CBM reservoirs. CBM recovery factors follow a log-logistic distribution, with a P50 of 38%. We extended the distribution of gas recovery factors gained from our analyses of U.S. coals to estimate global CBM TRR. Global technically recoverable CBM is estimated to be 500 (P90) to 3,000 (P10) Tcf, with a P50 value of 1,600 Tcf.

UGRAS is a robust tool that may be used to evaluate and rank coalbed methane gas resources worldwide. Results of this work verify the existence of significant technically recoverable coalbed methane resources worldwide and can guide industry to better target its exploitation efforts in coals, worldwide.
A Novel Completion Method for Sequenced Fracturing in the Eagle Ford Shale
Authors: Kraemer C. , Lecerf B. , Torres J. , Gomez H. , Usoltsev D. , Rutledge J. , Donovan D. , Philips C.
Published: June 2014

In multistage fracturing of unconventional formations such as the Eagle Ford shale, wells are traditionally stimulated by fracturing several perforation clusters simultaneously. While the technique is operationally efficient, there is evidence from production logs, microseismic monitoring, and other measurements that several clusters produce below expectations or do not produce at all. This condition is to a degree because stages penetrate zones with stress heterogeneities, and consequently, fractures propagate unevenly from all of the clusters.

Evenly fracturing all clusters in heterogeneous zones is challenging in long horizontal sections penetrating heterogeneous reservoirs. Furthermore, efforts to improve well economics result in reducing completion time by extending the length of each stage even further to decrease the number of interventions required for completing the well. To address this challenge, a new sequenced fracturing technique has been developed based on a novel composite fluid comprising of degradable fibers and multi-sized particles that diverts the remaining stimulation fluids to understimulated regions of the wellbore. The composite fluid is delivered downhole at high-concentration, to create temporary plugs in clusters already stimulated thereby creating diversion with a minor amount of material. The solids degrade completely after the fracturing treatment has been completed, leaving no residual formation or fracture conductivity damage. The channel fracturing technique (Gillard et al. 2010) was chosen as the preferred fracturing method for use in tandem with the composite fluid. This technique has been reported to increase effective fracture length while reducing risk of screenout with respect to other conventional methods.

The new composite fluid was used in a campaign where its effects were monitored with microseismic instruments. A case study presents field experiments where wells from the same pad are fractured in a similar fashion with and without diversion. In one application, with similar water and fluid volumes, the well treated with this technique produced more than 15% per stage than its conventionally treated offset well. The signature of the composite fluid, clearly visible on all measurement techniques, has proven consistent across stages of various lengths and wells having different characteristics.
How Reliable Is Production Data Analysis?
Authors: Anderson D. M. , Thompson J. M.
Published: June 2014

It is well known that the analysis of production data (Rate Transient Analysis) involves the solution of an inverse problem. We measure the response of the system, typically production rates and flowing pressures, and then proceed to search for the appropriate reservoir model description that created it. Typically, this is accomplished through the minimization of an objective function consisting of the difference between the simulated response and the actual response. In practice, production analysis is complicated by two important problems: 1) The mathematical models (analytical or numerical) that we use to describe well production may not provide an adequate and full description of the true well-completion-reservoir system. This is especially true if the system is complex and asymmetric, as is the case in unconventional plays. And 2) The production response almost certainly contains significant errors and/or disturbances caused by outside influences. This makes the process of error minimization difficult and non-unique. As a result, it is impossible to know whether or not we are obtaining reliable results from production analysis, as there are simply too many unknown variables in the system we are trying to model.

The objective of this work is to determine the best procedure for solving the inverse problem of production analysis in a consistent and reliable way, and to quantify just how reliable the results are. We wish to do this in an environment free of complications, such as those identified previously in 1) and 2). To accomplish this, simulated production responses from known models are analyzed, but the full set of model input parameters are withheld; only basic input parameters are provided, such as what would typically be available in practice. Since the "answer key" is available, this study allows us to objectively evaluate and optimize production data analysis best practices.
Computational Prediction of Solvent and Surfactant Properties Using the Conductor-Like Screening Model (COSMO) For Chemical Enhanced Oil Recovery Research
Authors: Bennetzen Martin V. , Andersen Jin U. , Mogensen Kristian
Published: June 2014

Enhanced oil recovery (EOR) methods often involve water-based flooding where surfactants, co-solvents and/or other chemicals are present in the aqueous phase being injected into the oil-bearing rock. The chemical flood may facilitate oil recovery by altering physical and chemical properties of the water-oil-chemical(s) system present in the porous medium such as interfacial tension, phase partitioning and liquid-liquid mixing. Prior to testing the efficiency of a chemical flood, initial laboratory experiments are routinely conducted to investigate the phase behaviour and thermodynamic properties (e.g. brine compatibility) of the present fluid system. However, such laboratory screening experiments consume significant time that scales linearly with the number of chemicals and combinations hereof to be characterized.

The Conductor-Like Screening MOdel (COSMO) has been developed over the last decades with the aim of predicting thermodynamics of complex mixtures based on single-molecule charge distributions. The charge distributions are calculated based on the molecular structure using density functional theory (DFT) to estimate molecular energies of quantum mechanical origin. Despite the fact that applications of COSMO have predominantly been used for biomedical, environmental, and chemical engineering research, applications of the theory show great promise for EOR research.

In this paper we demonstrate the versatility of applying the COSMO-theory to predict thermodynamic properties of water-oil systems, such as liquid-liquid mixing, phase partitioning, solubility, interfacial tension and ternary phase diagrams. Moreover, we describe an in-house developed database of 3D charge density landscapes of 100+ surfactants and present an in-depth analysis hereof with respect to single molecule properties as well as water-oil-surfactant system properties. Strikingly, we show that COSMO-theory in combination with a specific application of probability theory and the method of moments (MoM) can be used to estimate system properties such as interfacial tension, critical micelle concentration and phase partition coefficients.

We demonstrate that COSMO-theory provides a powerful framework for large-scale, fast and inexpensive initial computational prediction of single-molecule and continuum system properties. In particular we foresee that future applications of COSMO-theory to accurately estimate model input-parameters for chemical EOR simulators, such as UTCHEM, would be highly beneficial to the EOR research community.
Micro-Scale Experiment and CFD Modeling of Viscoelastic Polymer; Trapped Oil Displacement and Deformation at the Dead-End
Authors: Afsharpoor Ali , Ma Kun , Mateen Khalid , Duboin Aurélien , Jouenne Stephane , Cordelier Philippe
Published: June 2014

Polymers are used in enhanced oil recovery (EOR) to control the mobility ratio between displaced fluid (oil) and displacing fluids (water). Polymer improves sweep efficiency by overcoming gravity overriding, viscous fingering, and channeling. For many years, improving sweep efficiency was considered the only significant mechanism to increase the oil recovery in polymer-flooding. But recently, experimental and field data suggest that viscoelastic polymers such as hydrolyzed polyacrylamide (HPAM) improve displacement efficiency as well and reduce the residual oil saturation. One of the hypotheses is that the elasticity of polymer triggers the pulling-effect on the trapped oil at the dead ends, thus leading to the mobilization of the trapped oil.

In this study, micro-scale experiments were done to prove or disprove the hypothesis of viscoelasticity pulling-effect. Then, steady-state (static) CFD modeling was performed in the dead ends of the porous medium to analyze the flow characteristics of viscoelastic polymer. The streamlines, velocity contours, and normal stress contours are discussed here. Both, experimental work and steady-state simulation results show that the oil can be barely mobilized in normal reservoir condition mimicked by the micro-scale experiments.

Additionally, transient (dynamic) CFD modeling was carried out for a better understanding of oil droplet movement and deformation at dead-end geometry. The Arbitrary Lagrangian-Eulerian (ALE) finite-element formulation is used to keep track of interface between oil and the displacing fluid. The dynamic simulation results are in agreement with static simulation and experimental results. This study shows that with normally used viscoelastic polymers, the pulling-effect is not the main mechanism resulting in reduced residual oil saturation. However, ways increasing of the Deborah number through potential means, such as using polymer with higher relaxation time, may result in a more significant pulling effect and thereby recover residual oil.
Switchable Amine Surfactants for Stable CO2/Brine Foams in High Temperature, High Salinity Reservoirs
Authors: Elhag Amro S. , Chen Yunshen , Chen Hao , Reddy Prathima P. , Cui Leyu , Worthen Andrew J. , Ma Kun , Hirasaki George J. , Nguyen Quoc P. , Biswal Sibani L. , Johnston Keith P.
Published: June 2014

Ethoxylated amine surfactants of the form C12-14N(EO)x have been characterized for foam generation to improve the sweep efficiency for CO2 enhanced oil recovery (EOR) up to 120 °C in the presence of high salinity brine of 22%TDS. These surfactants are switchable from the nonionic (unprotonated amine) state in dry CO2 to cationic (protonated amine) in the presence of an aqueous phase with a pH below 6. Potentiometric titration of two surfactants with 2 or 15 EO groups was conducted at 90 °C to test the switchability of the surfactant from nonionic to cationic forms at different pH values. Ethoxylated amine with 2 EO groups showed more affinity for protonation when compared to 15 EO due to the hinderance effect of the larger molecule that covers the ionizable nitrogen head. For C12-14N(EO)2, viscous C/W foams were produced by injecting the surfactant either in the CO2 phase or the brine phase, which indicates good surfactant transport to the interface in either case. The optimum foam quality was observed at 90% and 95% when the surfactant was injected from brine phase or CO2 phase, respectively. C12-14N(EO)2 was effective in lowering the interfacial tension between water and CO2 at 120 °C and 22%TDS from ~ 40 mN/m to 5 mN/m with CMC value of 0.038 mM. This significant reduction in interfacial tension enhances foam generation and foam stability.
Listening to the Data: An Analysis of the Oil and Gas Journal Database
Authors: Lake Larry W. , Yang Andrew , Pan Zhong
Published: June 2014

The Oil and Gas Journal (OGJ) biennial survey on EOR projects has been a partner to the IOR Symposium since early time. Plots of EOR projects versus time, taken from the survey, have been a mainstay of plenary talks. But there is much more to be learned in the database, and the purpose of this work is to find out what can be learned from a broad analysis.

The paper uses standard statistical techniques to infer binary correlations between data sets. With fewer than 300 US projects, the analysis by no means meets the standards of Big Data, but there are things to be learned, nevertheless, because of the scope of survey: It includes all projects worldwide, surveys since 1986, and covers all EOR processes. However, some processes are more represented in the surveys than others, so these are analyzed in the most detail.

We also perform more sophisticated analysis using the conditional probability theorem to infer the probability of success of steam EOR projects. We look at the OGJ survey from the view of screening as exemplified in the work of Taber et al. (1997), and updated by Dickson et al. (2010). In one sense our work is basically an attempt to see how well these guidelines have been followed in practice.
Single Well Pilot Test of Near Miscible CO2 Injection in a Kansas Arbuckle Reservoir
Authors: Tsau J. S. , Ballard M.
Published: June 2014

A recent study showed that CO2 injection at pressures below minimum miscibility pressure (MMP) improves oil recovery with Arbuckle reservoir core samples at near miscible conditions. To demonstrate its applicability on a larger scale, a single well pilot test was designed to experimentally inject CO2 into the Arbuckle formation at pressures below MMP to determine the efficiency of CO2 displacement at near miscible conditions.

The pilot test consists of a single-well chemical tracer (SWCT) test before and after CO2 injection on a selected well producing from the Arbuckle formation. The reservoir operating pressure was 1,150 psi while the MMP of the oil was 1,500 psi at 106 °F (reservoir temperature). The first chemical tracer test was performed to determine the oil saturation in the formation prior to CO2 injection. This was followed by injecting approximately 17 tons of CO2 at pressures below MMP with a follow up water displacement, followed by a second tracer test performed to determine the remaining oil saturation.

The oil saturation measured from the two tracer tests were 0.23 and 0.20, respectively. A reduction of oil saturation by 0.03 represents a 13% improvement of oil displacement which results from CO2 injection at near miscible conditions. The test results indicate the potential of using near miscible CO2 to improve oil recovery in Kansas Arbuckle reservoirs and others where MMP cannot be achieved.
Evaluation of Surfactants for Oil Recovery Potential in Shale Reservoirs
Authors: Nguyen Duy , Wang Dongmei , Oladapo Aderaje , Zhang Jin , Sickorez Jeffrey , Butler Ray , Mueller Brian
Published: June 2014

Most shale reservoirs (e.g., Bakken Shale and Eagle Ford) have a low permeability, low porosity, and oil-wet character with natural fractures. As a result, the oil recovery factors are very low, only a few percent of original oil in place. Injection of water into oil-wet reservoirs (i.e., water flooding) is not effective due to small or negative capillary pressure. In this study, various surfactants (non-ionic, cationic, anionic, and amphoteric) were studied for spontaneous imbibition into oil-wet shale cores. Surfactant imbibition into Eagle Ford shale outcrop cores and Bakken reservoir cores increased oil recovery compared to brine only. Oil recovery can be seen for surfactants that alter the reservoir from oil-wet to water-wet. For example, the incremental oil recovery was about 24% % for 0.1% cationic surfactant and 57% for 0.1% nonionic surfactant. The goal of this work is to investigate the effect of salinity, surfactant concentration, electrolyte concentration, and temperature on the wettability alteration and provide mechanisms. Contact angles and interfacial tensions (IFT) were measured and correlated with spontaneous imbibition. Wettability alteration from oil-wet to water-wet (i.e., low contact angle) appeared to be more important than a low interfacial tension in increasing the oil recovery rate from fractured oil-wet reservoirs, especially for nonionic surfactants and amphoteric surfactants. Wettability alteration is maximum and IFT is minimum for anionic and cationic surfactants at an optimal salinity. However, as the reservoir salinity increases, the maximum wettability alteration decreases and IFT increases.
Study Nanoparticle-Stabilized CO2 Foam for Oil Recovery at Different Pressure, Temperature, and Rock Samples
Authors: Mo Di , Jia Bao , Yu Jianjia , Liu Ning , Lee Robert
Published: June 2014

This paper presents a series of studies the nanoparticle-stabilized CO2-foam for waterflooded residual oil recovery. Nanosilica-stabilized CO2 foam has been observed to improve oil recovery after waterflooding in sandstone. The effects of pressure, temperature, and rock samples on the performance of CO2 foam on residual oil recovery were investigated. The results indicated that the residual oil recovery (percent of waterflooded residual oil) by CO2/nanosilica flooding increased from 64.9% to 75.8% when the pressure was increased from 1,200 psi to 2,500 psi. When temperature increased from 25°C to 60°C, the residual oil recovery by CO2/nanosilica flooding decreased from 62.6% to 52.1%. The particle-stabilized CO2 foam was also observed to improve oil recovery from limestone and dolomite after waterflooding. The results also suggested that particles plugging-in probably occurred in dolomite during the CO2 foam core flooding test.
New Insights on the Role of Multivalent Ions in Water-Carbonate Rock Interactions
Authors: Kwak Hyung T. , Yousef Ali A. , Al-Saleh Salah
Published: June 2014

The current study is focused on the effects of the individual key ions (Ca2+, Mg2+, (SO4)2-) along with a few of other common ions (Na+ and Cl-) on carbonate rock by only injecting water with controlled amount of individual or combined ions into the selected carbonate rock at reservoir temperature. A low field NMR technique has been a tool of choice for the current work since it allows monitoring the physical and chemical alteration of rock surface after interacting with fluids which contain specific types and amount of ions. In addition, since NMR is non-destructive measurement, the effect of various types of fluids with the identical rock sample before, during, and after core flooding test can be monitored repeatedly.

NMR results indicate that the water-rock interaction changes when injecting different types of ions. The interaction a of key divalent key ions, Ca2+, Mg2+, and (SO4)2-, on the carbonate rock surface are observed with relatively weak reactivity of Ca2+ compare to the other two. At the reservoir temperature, 90°C, the reactivity of Mg2+ with the carbonate rock is greater than that of Ca2+. The reactivity of multivalent anion (SO4)2- is also significant with carbonate rock surface, but it will induce surprising behavior on NMR response. The fundamental understandings acquired by the current study, effects of key ions in carbonate rock with single-phase fluid will be one of the key building blocks to develop rigid understanding of more complicated multi-phase fluid interaction with various types of reservoir rocks, and eventually draw conclusions on how these ions change rock wettability.
Scale up of Reactive Processes in Heterogeneous Media - Numerical Experiments and Semi-Analytical Modeling
Authors: Singh Harpreet , Srinivasan Sanjay
Published: June 2014

Performance prediction of reactive processes such as those associated with injection of chemicals that react with rock and fluids require accurate models for the processes. Frequently, these processes are studied at laboratory scale and modeling them at the field scale entails scaling-up of laboratory observations taking into account the spatial variability of parameters. The current practice is to perform spatial averaging of attributes and account for residual variability by calibration and history matching. This results in poor predictions of future reservoir performance. In this paper we scale-up such reactive transport processes considering both the spatial and temporal characteristics of these processes.

The first part of the paper investigates spatiotemporal scale-up of dispersivity accounting for field heterogeneity and reactivity of CO2. In this case, we investigate scale up by performing numerical simulations. Transport processes in reservoir models at three different length scales are simulated assuming homogeneous and heterogeneous permeability models. The variation in dispersivity with spatiotemporal scale is plotted and various conclusions are deduced regarding the impact of the permeability and conservative/reactive transport on the scale up characteristics of disersivity and mixing zone length. In the second part of the paper, a semi-analytical model for spatiotemporal covariance describing the reaction-dispersion process is used to derive the Representative Elementary Volume (REV) of concentration in combined space and time. The spatiotemporal covariance is used to compute the variance of mean concentration and REV is defined as the space-time scale over which the stabilization of this variance is achieved.

Key results of this work are that the scaling characteristics of dispersivity distinctly differ for low permeability and high permeability media. Heterogeneous media with spatial arrangements of both high and low permeability regions exhibit scaling characteristics of both high and low permeability media. Another important result is that reactions affect scaling characteristics of dispersivity in heterogeneous media. The semi-analytical models for scale-up of reaction-dispersion processes indicate that purely spatial or temporal investigation does not produce accurate estimate of REV. However, when scaling is investigated in a spatiotemporal setting, then the REV can be defined fairly accurately.

These results can be important for designing laboratory experiments and to predict scaled-up field response. Additionally, results also demonstrate that spatiotemporal numerical discretization of recovery processes for representing them in numerical flow simulations should be done appropriately based on the combined spatiotemporal REV scale of the process.
Experimental and Numerical Assessment of Chemical EOR in Oil-Wet Naturally-Fractured Reservoirs
Authors: Bourbiaux Bernard , Fourno André , Nguyen Quang-Long , Norrant Françoise , Robin Michel , Rosenberg Elisabeth , Argillier Jean-François
Published: June 2014

Among various ways to extend the lifetime of mature fields, chemical EOR processes have been subject of renewed interest in the recent years. Oil-wet fractured reservoirs represent a real challenge for chemical EOR as the matrix medium does not spontaneously imbibe the aqueous solvent of chemical additives. However, a wide variety of surfactants can now be considered for EOR, among which products that alter the matrix wettability. The present paper deals with that recovery strategy and compares it with other strategies based on viscous drive enhancement. Comparison is based on the physical and numerical interpretation of original representative experiments.

The kinetics of spontaneous imbibition of chemical solutions in oil-wet limestone plugs and mini-plugs has been quantified thanks to X-ray CT-scanning and NMR measurements. Despite the small size of samples and the slowness of experiments, accurate recovery curves could be inferred from in-situ fluid saturation measurements. Scale effects were found quite consistent between mini-plugs and plugs. During a second experimental step, representative drive conditions of a fractured reservoir were imposed between the end-faces of a plug, in order to account for the possibly-significant contribution of fracture viscous drive to matrix oil recovery.

These experiments were carefully analyzed and their numerical modeling was initiated with a simulation software that takes into account the multiple effects of surfactant presence on rock-fluids systems, including rock wettability modification and water-oil interfacial tension reduction. Model capability to reproduce experimental results is quite satisfactory provided that the evolution of capillary pressures in the presence of additives is sufficiently characterized. A few sensitivity studies underline also the necessity of disposing of a completely-documented physico-chemical data set to minimize modeling uncertainties in view of reliable recovery kinetics optimization.

In summary, the present paper provides an original quantitative description of chemical EOR process in neutral to oil-wet fractured reservoirs. This work calls for further development in order to specify the conditions on chemical additives and recovery process implementation that satisfy economic viability.
Diffusion and Matrix-Fracture Interactions during Gas Injection in Fractured Reservoirs
Authors: Shojaei Hasan , Jessen Kristian
Published: June 2014

Molecular diffusion can play a significant role in oil recovery during gas injection in fractured reservoirs. Diffusion of gas components from a fracture into the matrix extracts oil components from matrix and delays, to some extent, the gas breakthrough. This in turn increases both sweep and displacement efficiencies.

In current simulation models, molecular diffusion is commonly modeled using a classical Fick's law approach with constant diffusion coefficients. In the classical Fick's law approach, the dragging effects (off-diagonal diffusion coefficients) are neglected. In addition, the gas-oil diffusion at the fracture-matrix interface is normally modeled by assuming an average composition at the interface which does not have a sound physical basis.

In this paper, we present a dual-porosity model in which the generalized Fick's law is used for molecular diffusion to account for the dragging effects; and gas-oil diffusion at the fracture-matrix interface is modeled based on film theory in which the gas in fracture and oil in the matrix are assumed to be at equilibrium. A novel shape factor is also introduced for gas-oil diffusion based on film theory. Diffusion coefficients are calculated using the Maxwell-Stefan model and are pressure, temperature and composition dependent. A time-dependent transfer function is used for matrix-fracture exchange in which the shape factor is adjusted using a boost factor to differentiate between the transfer rate at early and late times.

Field-scale examples are used to demonstrate that the dragging effects (off-diagonal diffusion coefficients) can significantly impact the oil recovery during gas injection in fractured reservoirs. It is also shown that using proper physical models for matrix-fracture interactions (film theory for gas-oil diffusion and transfer function with boost factor) can considerably affect the simulation results as compared to conventional models. We also show that miscibility is not developed in the matrix blocks even at pressures above minimum miscibility pressure (MMP) when molecular diffusion is the main recovery mechanism during gas injection in fractured reservoirs.

The work presented in this paper is directly applicable to the study and design of gas injection processes in fractured reservoirs through an improved understanding of the effect of diffusion and matrix-fracture interactions on these processes.
CO2 Foam Pilot in Salt Creek Field, Natrona County, WY: Phase I: Laboratory Work, Reservoir Simulation, and Initial Design
Authors: Mukherjee J. , Norris S. O. , Nguyen Q. P. , Scherlin J. M. , Vanderwal P. G. , Abbas S.
Published: June 2014

In this paper we describe the design of a CO2 foam pilot in the Salt Creek Light Oil Unit in Natrona County, WY. CO2 foam technology was chosen as a promising candidate to improve sweep efficiency in certain target patterns. The second Wall Creek (WC2) sandstone formation is the primary producing interval, with a net thickness of about 80 feet and at a depth of approximately 2,200 feet. The first screening step towards identifying a pilot area involved a detailed study of the geologic features, injection-production characteristics, and operational aspects of numerous patterns in the field. An injector centered five-spot pattern was selected for the pilot. A surfactant formulation was developed that provided the desired foam response at reservoir conditions, and also met preliminary economic and operational expectations. The foam characteristics of the surfactant were further investigated by performing core-flood experiments. A history matched reservoir simulation model was developed to forecast the performance of the field in the absence of foam and thus provide a baseline to compare with the anticipated foam response. The model was later calibrated with foam performance data and used to guide the implementation of the pilot and to forecast field performance. The pilot was initiated in September 2013. Initial results are discussed.
Methane Production from Natural Gas Hydrates by CO2 Replacement – Review of Lab Experiments and Field Trial
Authors: Hauge L. P. , Birkedal K. A. , Ersland G. , Graue A.
Published: June 2014

Natural gas hydrate is a crystallized ice-like substance, consisting of water and natural gas, with methane as the most common gas. Water molecules form cages through hydrogen bonding and encapsulate gas molecules. Natural gas hydrates are found in the earth under high pressure and low temperature where water and gas co-exist, typically in permafrost and sub- marine environments. Hydrates have been considered a nuisance in the petroleum industry, creating barriers in pipe lines, and effort has mainly been put into preventing hydrate formation. However, natural gas hydrates are in recent decades acknowledged as a potential energy resource for the future; even conservative estimates suggest 1015 m3 CH4 STP present within hydrate.

Several methane production scenarios are proposed: thermal-, chemical- and pressure reduction induced dissociation is available, although depressurization is considered the least costly option. The University of Bergen has since 2002 worked on a fourth alternative: exchange of CH4 molecules with CO2. Lab scale experiments have repeatedly shown CO2-CH4 exchange within sediments. These experiments led to a field trial test in Alaska, operated by ConocoPhillips, by utilizing CO2 injection as a production method. Similar procedures as in the field test were performed in the lab, creating repetitive data for analysis on lab scale. This paper reviews results from both the laboratory and field pilot and discusses challenges and mitigating measures related to production.
Expandable Liner Hangers in Off-Bottom Cementing Applications Reduce Cost and Increase Reliability: Regional Case History
Authors: Hayward Daniel , McCormick John , Matice Marilyn , Dickinson James
Published: June 2014

The oilfield continues to experience increasing material costs for land wells as well as hydrocarbon depletion in common shallow reservoirs. To offset the resulting impact on profitability, reducing rig time and cost with new technologies has been critical for maintaining project profitability.

This paper is intended to inform operators of the advancements made with off bottom cementing (OBC) system technology, including a diverter (DV) tool, which is the crux of this system. This paper will also consider new well design opportunities that will not only improve reliability, reduce installation time and increase versatility in new drills but also can be implemented in pre-existing land wells.

This paper incorporates case histories in which four original OBC applications in South Texas provided consistent material cost savings and improved reliability while providing the capacity to strategically isolate adverse zones above the target formation. The paper will demonstrate consistent reduction in overall well cost by enabling the elimination of a five inch casing string that was designed in the original well plan. The new OBC plan provided a larger openhole ID section with more surface area to the target formation.