bluuebunny/crossref_metadata_2025 huggingface dataset:
Determining Relative Permeability In Shales By Including The Effects Of Pore Structure On Unsaturated Diffusion And Advection
Authors: Daigle Hugh , Ezidiegwu Sandra , Turner Raymond
Published: September 2015

Existing models for shale permeability couple advection and diffusion but do not include the effects of fluid saturations on the permeability. Using a combination of critical path analysis, effective medium theory, and percolation theory, we modeled shale relative permeability by considering the effects of pore structure on unsaturated advection and diffusion. Relevant percolation properties were determined from N2 adsorption-desorption measurements. We considered samples of Green River Shale, Woodford Shale, and Cameo Coal, and isolated kerogens from the Green River and Woodford. We considered gas to be the wetting phase in the kerogens and coal and the nonwetting phase in the bulk shales. We found that the nonwetting phase relative permeability scales linearly with the nonwetting phase saturation, while the wetting phase relative permeability exhibits a highly nonlinear relationship with wetting phase saturation due to the large pore space fractal dimensions (>2.68) of the shales. Based on our model, we predict that water production from the shales is expected to be minor until the gas phase reaches its residual saturation, and that the rate of gas transport out of the kerogen and into the shale matrix should decrease rapidly following the onset of production. This may explain in part why shale gas wells typically produce little formation water and exhibit rapid production decline rates.
Stochastic Modeling of a Fracture Network in a Hydraulically Fractured Shale-Gas Reservoir
Authors: Mhiri A. , Blasingame T. A. , Moridis G. J.
Published: September 2015

This study introduces a novel approach to model the hydraulic fractures in a shale reservoir using a common stochastic method called “random-walk.” The goal of this work is to capture part of the “complexity” of a fracture/fracture network that has been generated by a hydraulic fracturing treatment and to attempt to characterize this fracture network using reservoir performance signatures.

The steps involved in this work are:

Stochastic generation of a “random-walk” fracture pattern constructed as a scaled numerical model. Assessment of the “random-walk” fracture using sensitivity analyses which consider the following elements: — The tortuosity (i.e., the actual length to ideal length ratio) — The tendency to branch (or split). — The number of branching stages — the number of branches was held constant for a given set of cases. Comparison of the mass rate and beta mass rate-derivative performance of the various “random-walk” fracture cases compared to the “standard” model of a planar fracture.

The primary results of this work are:

Generation of pressure distributions (maps) at given times (i.e., “time slices”) to qualitatively assess each complex-pattern during transient production. The pressure distribution figures (i.e., maps) are used to qualitatively determine the presence of fracture interference(s) and to identify a time interval where those interferences occur. Creation of a graphical correlation of reservoir performance in terms of cumulative recovery as a function of the fracture volume and “fracture complexity” (i.e., the number of branches). Creation of an empirical correlation between the number of branches in a given fracture pattern and the value of the mass rate beta-derivative during transient flow (we observed that the mass rate beta-derivative is essentially constant during transient flow regardless of the fracture network configuration, as such this constant value of the mass rate beta-derivative was selected for correlation).

This work provides an alternative description of hydraulic fractures in unconventional shale-gas reservoirs which, in concept, captures the complexity of the hydraulic fracture as a stochastic fracture network.

Early-time rate performance is believed to be an indicator of the geometry of the hydraulic fracture pattern. A fracture with a higher level of “complexity” yields higher values of mass rate beta-derivative when the fractures components are interfering with each other. Therefore, mass rate curves could be used as a diagnostic tool that helps the identification of the fracture geometric features.
Modeling Impact of Geochemical Reactions on a Real Reservoir Fluid Mixture During CO2 EOR
Authors: Venkatraman Ashwin , Dindoruk Birol , Elshahawi Hani , Lake Larry W. , Johns Russell T.
Published: September 2015

CO2injection in oil reservoirs has the dual benefit of enhancing oil recovery from declining reservoirs as well as sequestering a greenhouse gas to combat climate change. CO2injected in carbonate reservoirs, such as those found in the Middle East, can react with ions present in the brine and the solid calcite in the carbonate rocks. These geochemical reactions impact the overall mole numbers and in some extreme cases, even the number of phases at equilibrium impacting oil recovery predictions obtained from compositional simulations. Hence, it is important to study the impact of geochemical reactions on a real reservoir fluid mixture during CO2injection. In this study, the Gibbs free energy function is utilized to integrate phase behavior computations and geochemical reactions to find equilibrium compositions. The Gibbs free energy minimization method using elemental balance constraint is used to obtain equilibrium compositions arising at phase and chemical equilibrium. The solid phase is assumed to be calcite, the hydrocarbon phases are characterized using the Peng-Robinson (PR) Equation of State (EOS), and the aqueous phase components are described using the Pitzer activity coefficient model. The binary interaction parameters for the EOS and the activity coefficient model are obtained using experimental data.

The impact of the changes in phase behavior of a real reservoir fluid with 22 components is presented in this manuscript. We observe that the changes in phase behavior of the resulting reservoir fluid mixture in the presence of geochemical reactions depend on two factors: 1) the volume ratio (and hence molar ratio) of the aqueous phase to the hydrocarbon phase and 2) the salinity (and composition) of the brine. These changes represent a maximum impact of geochemical reactions since all reactions are assumed to be at equilibrium. This approach can be adapted to any reservoir brine and hydrocarbon as long as the initial formation water composition and their Gibbs free energy at standard states are known. The resultant model can be integrated into any reservoir simulator as integrated algorithms can be used for minimizing the Gibbs free energy function of the entire system.
Dynamics of Fracture-matrix Coupling during Shale Gas Production: Pore Compressibility and Molecular Transport Effects
Authors: Wasaki Asana , Akkutlu I. Yucel
Published: September 2015

Much work has been done to demonstrate an economical impact of various fluid transport mechanisms on the long term behavior of shale gas production. These studies were elementary level and focused on identifying a dominant mechanism of production. They did not consider, however, the interaction of the fractures with the shale matrices in detail. In the near wellbore environment the fracture is the crucial component of transport, whereas the matrix is the place for storage. In this paper, using a new in-house reservoir flow simulator, we introduce the nature of this interaction and show that the transport in the tight matrix can be induced by carefully designing the well completions and by operating under the optimum production conditions.

The simulator accounts for a hydraulic fracture coupled to shale matrix with an anistropic apparent permeability field, which is stress-sensitive and includes the effects of molecular transport phenomena. The fracture has a dynamic conductivity with a simple nonlinear deformation rule reflecting proppant embedment effect on the conductivity. Using a sector model, we predict short-term cumulative production trends. The results indicate that design of horizontal wells with multiple fractures should take into account the geomechanical and diffusional resistances associated with the gas transport in the matrices. Further, in-series nature of the production indicates that changes in fracture conductivity beyond its threshold value has negligible effect on the production trends. Therefore, production optimization efforts should instead focus to considerations to improve the flow rates in the matrix.
Enhanced Oil Recovery in Liquid-Rich Shale Reservoirs: Laboratory to Field
Authors: Alharthy Najeeb , Teklu Tadesse , Kazemi Hossein , Graves Ramona , Hawthorne Steven , Braunberger Jason , Kurtoglu Basak
Published: September 2015

Production of tight oil from shale reservoirs in North America reduces oil imports and has better economics than natural gas. Consequently, there is a strong interest in oil production from Bakken, Eagle Ford, and Niobrara. However, oil recovery factor for Bakken remains low, which is about four to six percent of the oil in place. Even with this low oil recovery factor, Bakken recoverable reserves are estimated to be 7.4 billion barrels; thus, a large volume of oil will remain unrecovered. This low level of oil recovery was the motivation to investigate the feasibility of enhanced oil recovery (EOR) in liquid-rich shale reservoirs such as Bakken.

In this paper, we will present both laboratory and numerical modeling of EOR in Bakken cores using CO2, C1-C2 mixture, and N2. The laboratory experiments were conducted at the Energy and Environmental Research Center (EERC). The experiments recovered 90+ percent oil from several Middle Bakken cores and nearly 40 percent from Lower Bakken cores. To decipher the oil recovery mechanisms in the experiments, a numerical compositional model was constructed to match laboratory oil recovery results. We concluded that solvent injection mobilizes matrix oil by miscible mixing and solvent extraction in a narrow region near the fracture-matrix interface, thus promoting counter-current flow of oil from the matrix instead of oil displacement through the matrix. Specifically, compositional modeling results indicate that the main oil recovery mechanism is miscible oil extraction at the matrix-fracture interface region. However, the controlling factors include re-pressurization, oil swelling, viscosity and interfacial tension reduction, diffusion-advection mass transfer, and wettability alternation.

We scaled up laboratory results to field applications via a compositional numerical model. For field applications, we resorted to the huff-and-puff protocol to assess the EOR potential for a North Dakota Middle Bakken well. We concluded that long soak times yields only a small additional oil compared to short soak times, and re-injecting wet gas, composed of C1,C2, C3, and C4+, produces nearly as much oil as CO2 injection.
Improved NMR Logging Approach to Simultaneously Determine Porosity, T2 and T1
Authors: Coman Radu , Tietjen Holger , Thern Holger , Blanz Martin , Christensen Søren Amdi
Published: September 2015

The simultaneous measurement of T1 and apparent-T2 relaxation times of a movable fluid with a nuclear magnetic resonance (NMR) logging-while-drilling (LWD) tool significantly increases the robustness of measured porosity at elevated rates of penetration. A new processing method is the basis for improved NMR logging products including water saturation, permeability prediction, pore size distribution, and oil viscosity estimation.

Current NMR-LWD acquisition and processing methods treat T2 relaxation times and T1 relaxation times independently. NMR tools with high magnetic field gradients and tools powered with batteries are practically restricted to the T1 measurement, whereas tools with low magnetic field gradients powered by a mud-flow alternator usually run in an acquisition mode that provides only a T2 distribution. The processing method presented here simultaneously provides a full T2 distribution corrected for axial-motion effects (polarization effect and flow effect) as well as the T1 relaxation time of the movable fluid.

The method employs two T2 echo trains with various wait times and uses the amplitude ratio of the movable fluid to estimate the geometric mean of T1 for that fluid. The algorithm takes into account not only the polarization effect on the measured porosity caused by a finite wait time, but also the polarization effect caused by an elevated logging speed.

This new approach is especially useful for reservoirs with gas, vuggy porosity or light hydrocarbon where T1 of the movable fluid is large and the usual acquisition approach requires a correspondingly long wait time. By computing T1 with the presented approach, and by using it to correct for polarization effects, shorter polarization times can be employed, which can improve vertical resolution. Moreover, the polarization correction and the flow correction improve the accuracy of NMR-derived porosity and significantly expand the logging speed range for high-quality NMR-LWD applications. The advantages of the new method are proven by a log data example from a light hydrocarbon reservoir.
Development of a Mechanistic Numerical Simulator for Preformed Particle Gel Applications in Non-Crossflow Heterogeneous Reservoirs
Authors: Imqam Abdulmohsin , Goudarzi Ali , Delshad Mojdeh , Bai Baojun
Published: September 2015

Water channeling is caused by reservoir heterogeneities that lead to the development of high-permeability streaks. A recent interest in microgel treatment using preformed particle gels (PPGs) has drawn more attention to reducing excess water production, improving sweep efficiency, and enhancing macroscopic oil recovery. The objective of this paper is to gain an inclusive understanding of PPG transport mechanisms through heterogeneous reservoirs. A numerical simulator was developed to characterize the propagation of PPGs through given reservoir. The simulator was used to optimize the gel treatment design to enhance oil recovery from un-swept, low-permeability, and oil-rich zones. A novel core flooding experiment was conducted to validate the developed mechanistic models. The experimental results using heterogeneous permeability model without cross flow showed large incremental oil recovery from the low permeability sand pack after treatment with PPGs. The developed models were implemented into the gel transport reservoir simulator to aid in the design and to optimize the water control processes using PPGs. The results obtained from the simulator indicated a good match with core flooding experiment results. The sensitivity analysis showed incremental oil recovery was strongly dependent on the permeability contrast, PPG concentration, and PPG treatment size.
An Investigation on the Impact of Heterogeneity on Fluid Injectivity Loss during Water-Alternating-Gas Injection in Carbonate Formations
Authors: Saneifar Mehrnoosh , Heidari Zoya , Linroth Mark
Published: September 2015

Water-Alternating-Gas (WAG) injection technique has been widely applied to improve sweep efficiency of gas injections in depleted oil fields. However, injectivity abnormalities have been a limiting factor, adversely impacting the success and the economic feasibility of WAG projects. Heterogeneous distribution of petrophysical properties in carbonate formations are among parameters causing injectivity loss during WAG cycles. WAG injection reduces the effective fluid mobility in all rock classes, irrespective of their petrophysical properties and flow characteristics. Thus, a larger fraction of fluids flow into the rock classes of higher permeability, resulting in a poor frontal advancement in rock classes of lower permeability. This leads to reduced overall injectivity and loss of WAG operation efficiency. In this paper, we investigate and quantify the impact of spatial heterogeneity in a carbonate formation on injectivity loss during WAG injection.

We conduct automatic rock classification based on conventional well logs, using an unsupervised artificial neural network method, to characterize the rapid variation of petrophysical properties and mineralogy in a carbonate formation. We then apply a new heterogeneity coefficient to quantify the spatial distribution of rock classes. The introduced heterogeneity coefficient is validated using Principal Component and variogram analyses. The aforementioned technique was applied to ten wells of the SACROC unit, located in west Texas, subjected to WAG operation. Five of the selected wells in this field exhibited no injectivity abnormality, while the other five wells experienced unexpected low gas injectivity during CO2 injection and an apparent reduction in water injectivity during the follow-up brine injection. Rock classification generated three rock classes based on the distribution of porosity, permeability, pore types, and clay content. We quantified the magnitude of the spatial heterogeneity based on distribution of rock classes in all ten wells. We then investigated the impact of the heterogeneity on the injectivity loss during WAG injection by comparing the identified heterogeneity coefficients in all wells. The results showed that in the wells with WAG injectivity loss, the distribution of rock classes is approximately 30% more heterogeneous, compared to the wells with no injectivity loss. In the wells with injectivity loss, we also observed about 32% and 43% higher occurrence of rock classes 1 and 2, respectively, compared to the wells with no injectivity loss. An analysis of the formation spatial heterogeneity can be applied to improve selection of candidate wells for WAG injection and potential success of oil recovery projects.
Increasing Shale Gas Recovery through Thermal Stimulation: Analysis and an Experimental Study
Authors: Lin Yue , Wang HanYi , He Shuai , Nikolaou Michael
Published: September 2015

The Silurian Longmaxi shale gas play in the Jiaoshiba (JSB) structure in the southeast margin of the Sichuan Basin in China is studied to discuss the key factors that control the adsorption/desorption behavior of natural gas in shale formations. The rationale for this study is that understanding these factors can be helpful in shale gas stimulation designs that enhance recovery by combining hydraulic fracturing with thermally induced desorption of adsorbed shale gas.

The Jiaoshiba structure is a faulted anticline which experienced multiphase tectonic movement. The Longmaxi Formation has high thermal evolution degree with Ro more than 2.2%, and has a 35-45 meters thick high-quality shale (TOC > 2%) in its lower part. The reservoir is overpressure with a pressure coefficient of 1.55, and shale gas production and pressure are stable. Experimental measurements have indicated that more than 65% of the total gas storage in the Jiaoshiba shales exists as an adsorbed phase. Modeling the adsorbed phase can impact the selection of stimulation techniques as well as production forecasts. Adsorption generally cannot be determined accurately from history matching production data alone. The laboratory testing of actual shale samples from reservoir cores is important for characterizing shale gas adsorption behavior.

Previous laboratory studies have reported data from measurements at single temperatures, and the measured data have been represented by Langmuir isotherms. However, the effect of temperature on adsorption has not been explored. In this work, a series of experiments were conducted to measure adsorption curves for shale samples at various temperatures and depths from the Jiaoshiba shales. We investigated the representation of adsorption behavior as a function of both temperature and pressure.

The pressure-temperature dependent gas adsorption behavior is described by Bi-Langmuir model by fitting the unknown adsorption characteristic parameters against laboratory experiment data at low temperature, the gas adsorption behavior at higher temperature can be predicted by extrapolation from the model. The predicted gas adsorption capacity agree well with our experiment data, which demonstrate this model's capability to predict gas adsorption capacity at reservoir temperature based on data measured at laboratory conditions.

The pressure and temperature sensitive gas adsorption behavior is incorporated into an unconventional reservoir simulator, to investigate how thermal stimulation can impact shale gas production and ultimate recovery from hydraulic fractured shale formations. The results indicates that thermal stimulation has the potential to enhance shale gas recovery significantly by altering shale gas adsorption/desorption behavior through the elevation of formation temperature.
Reducing Reservoir Uncertainty During Appraisal and Development - Novel Applications of a new Wireless Reservoir Monitoring Technology in Santos Basin Pre-Salt
Authors: Champion B. P. , Puntel E. A.
Published: September 2015

Uncertainties in reservoir connectivity and compartmentalization risk are important considerations when thinking about any new field appraisal or development options. Having a better understanding of reservoir connectivity provides benefits in determining the appropriate drainage strategy and optimizing the field development plan. By the application of a new wireless reservoir monitoring technology, based on electromagnetic (EM) communications, it is now possible to monitor the reservoir pressure and temperature response during the long term suspension of development or appraisal wells. Accurate reservoir data can now be reliably collected in the period prior to a completion string being run, or a Xmas tree being installed on the well.

Petrobras is conducting an active programme of drilling and well testing evaluation in the Pre-Salt Santos Basin area, with the objective of maximizing the collection of reservoir data that can be used to prove the reservoir models. An opportunity was identified to utilize this wireless monitoring technology in some newly drilled development wells that were to be suspended for an extended period of up to 3 years. The primary monitoring objective was to gather dynamic reservoir pressure data that could be used to identify interference effects resulting from production or injection events in the adjacent field area. Any evidence of interference will serve to prove reservoir connectivity with the adjacent well assets.

A secondary monitoring objective was to record a long term pressure build-up, beyond the end of a Drill Stem Test (DST), to check for the presence of any reservoir boundaries located far from the wellbore.

Case histories are presented for 2 installations of the wireless technology in the Brazilian deepwater pre-salt environment. The first case history presents the installation of a wireless gauge system that successfully transmitted high quality pressure and temperature data to a subsea receiver for a period of 873 days until the receiver's recovery from the seabed. The results show clear evidence of inter-well interference resulting from production in both near and far located wells. With certain producing wells being located at least 12km away from the observation well, this demonstrates that there was excellent reservoir connectivity across the field.

The second case history was targeted at monitoring for interference effects resulting from an extended well test being performed on a well located 15km away. At the time of authoring this paper the survey has been on-going for 341 days and whilst there is no evidence of connectivity, the long term pressure build-up monitoring beyond the end of the DST has provided useful data.

For both case histories the data collected has proved very useful in reducing uncertainty during the early stages of field development.
An Efficient and Practical Workflow for Probabilistic Forecasting of Brown Fields Constrained by Historical Data
Authors: Yang Chaodong , Nghiem Long , Erdle Jim , Moinfar Ali , Fedutenko Eugene , Li Heng , Mirzabozorg Arash , Card Colin
Published: September 2015

Brown fields are fields with significant production history. Probabilistic forecasting for brown fields requires multiple history-matched models that are conditioned to available field production data. This paper presents a systematic and practical workflow to generate an ensemble of simulation models that is able to capture uncertainties in forecasts, while honoring the observed production data.

The proposed workflow employs the Bayes theorem to define a posterior Probability Density Function (PDF) that represents model forecast uncertainty by incorporating the misfit between simulation results and measured production data. Previous workflows use the Markov Chain Monte Carlo (MCMC) sampling method, which requires an extremely large number (thousands) of simulation runs. To alleviate this drawback, a Proxy-based Acceptance-Rejection (PAR) sampling method is developed in this study to generate representative simulation models that characterize the posterior PDF using hundreds of simulation runs. The proposed workflow can be summarized in five key steps: Run an initial set of reservoir simulations by simultaneously varying multiple uncertain parameters using an experimental design method.Construct a proxy function using a Radial-Basis Function (RBF) neural network to approximate the posterior PDF calculated from the initial set of simulation results.Sample the posterior PDF using the PAR sampling method and run an ensemble of new simulation models using the sample values.The new simulation results obtained in step 3 are added to the training datasets generated in step 1 to improve the accuracy of the proxy function. Steps 3 and 4 are repeated until a predefined stop criterion is satisfied.Filter all simulation runs generated in step 3 using appropriate tolerance criteria for various history-match quality indicators. The selected filtered cases constitute the final ensemble of simulation models that can be further used for uncertainty quantification in forecasting.

The proposed workflow is demonstrated on two reservoir simulation models: Synthetic case. The forecast uncertainty of the ninth SPE Comparative Solution Project (SPE9) simulation model is investigated with a synthetic production history and 32 uncertain parameters.Unconventional oil field case. The workflow is applied to an Eagle Ford shale oil well to determine P90 (conservative), P50 (most likely), and P10 (optimistic) cases of estimated ultimate recovery (EUR).

Results of the workflow are compared to those obtained using the Metropolis-Hasting MCMC sampling method. The comparison shows that the proposed workflow only requires 800 simulation runs to obtain results as accurate as the MCMC method with 8000 simulation runs. This translates into a 10- times speedup, which makes the proposed workflow practical for many real reservoir simulation studies.
Modeling Fishbones Using the Embedded Discrete Fracture Model Formulation: Sensitivity Analysis and History Matching
Authors: Cavalcante Filho Jose Sergio , Xu Yifei , Sepehrnoori Kamy
Published: September 2015

The fishbones technology is a new well stimulation technique developed to increase well productivity index and improve reservoir connectivity to the well, being an alternative to hydraulic fracturing. This technique consists of creating several branches (holes) in the well using acid injection (dissolution and diversion). Those branches have small diameter and an average length of 40 feet. Main advantages of this technology over hydraulic fracturing are the competitive price and reduced operation time. In this paper we aim at modeling fishbones using the embedded discrete fracture model (EDFM), originally developed to model conductive faults and fractures. An EDFM preprocessing code was rewritten and extended to generate non-neighboring connections (NNC) between matrix, fractures and well connections; the NNCs were exported and used as input for a numerical simulator capable to handle NNCs. We modified the EDFM preprocessing code to adequately model fishbones. Each fishbone branch is treated as a fracture with dimensions equivalent to the branch dimensions (radius and length). The use of appropriate equations based on Peaceman's equation allows to model fishbones as equivalent fractures. Our new approach was used to perform sensitivity analysis (one at a time method) of the reservoir properties and the number of fishbones' branches for a case of primary oil production. A history match of the results of the first pilot using the fishbone technology was performed using an automated algorithm. Triple porosity cases were also evaluated and a good agreement between simulation and production data was obtained. A sensitivity analysis using design of experiments and the regression technique was used to compare the application of fishbones in different reservoirs (isotropic, anisotropic, and fractured) under primary oil production. The results of the simulations show that the fishbones is a promising stimulation technology that should be further evaluated.
Simulation of Fracture-to-Fracture Gas Injection in an Oil-Rich Shale
Authors: Zhu Peixi , Balhoff Matthew T. , Mohanty Kishore K.
Published: September 2015

Miscible gas injection is proposed here for improved oil recovery in unconventional, oil-rich shale reservoirs. The ultra-low permeability of shale makes injection from well to well difficult; thus it is proposed that gas is injected into a hydraulic fracture along a horizontal well and production occurs from an adjacent fracture, intersecting the same well. Compositional reservoir modeling was performed to investigate the effectiveness of the proposed gas injection scheme. The computational domain consists of two hydrofrac half-stages along a horizontal well to capture detailed information of the fluid flow near the well bore. The results show 15.7% OOIP incremental recovery for the base model with matrix permeability kmatrix = 10 μD over 5000 days (nearly 14 years) of CO2 injection, and 12.5% OOIP for the one with kmatrix = 1 μD, indicating that the gas injection scheme has the potential to vastly improve oil recovery in oil-rich shale formations.

The effects of reservoir properties and injection conditions on oil recovery were investigated by changing the injection pressure, reservoir heterogeneity, hydrofrac spacing, dispersion, and compositions of the injection gas. Increasing injection pressure leads to higher production before breakthrough and faster recovery of the oil in the stimulated region. Reducing the hydrofrac spacing has similar effect, although the production declines more rapidly after breakthrough. Introducing heterogeneity to the reservoir results in lower recovery, but the effect of spatial continuity (correlation length) on recovery is insignificant. It was also found that dispersion is mainly dominated by diffusion and mechanical dispersion is less important in most cases. Injection of hydrocarbon gas outperforms CO2, especially if the economics is also taken into account.
Addressing Forecasting Non-Uniqueness and Uncertainty in Unconventional Reservoir Systems Using Experimental Design
Authors: Collins P. W. , Badessich M. Fernandez , Ilk D.
Published: September 2015

Model-based production analysis using analytical or numerical models is not a new phenomenon and is considered a robust technique for analyzing and forecasting production data; however, its application to unconventional reservoir systems often proves problematic due to model non-uniqueness resulting from long-term transient flow regimes. This non-uniqueness, an unavoidable fact when analyzing inverse problems, is worsened by the uncertainty surrounding input model parameters when attempting to describe reservoir systems with a great deal of complexity (e.g. very low permeability, geomechanical effects, near-critical fluids, natural fracturing, etc.). The problem facing the engineer presents itself when different combinations of input parameters yield nearly identical history matches but very different time-rate profiles and estimated ultimate recovery (EUR) values when forecasting future production for a particular well.

A systematic framework that covers the full range of uncertainty for all relevant input parameters would clearly mitigate the ambiguity of production analysis and forecasting under uncertain conditions. In this work it is proposed that experimental design, which is a statistical technique used to describe or optimize a process by systematically analyzing the effect of the various controllable and uncontrollable factors of a system on an output (e.g. EUR), can provide such a framework. In this work, a methodology combining model-based production analysis with experimental design is used to history match and forecast fractured vertical and multi-fractured horizontal oil wells in the Vaca Muerta Shale with high-frequency time-rate-pressure data. The primary objectives of this work are to provide a comprehensive overview of the Vaca Muerta shale, outline experimental design as it relates to model-based production analysis, quantify uncertainties in model input parameters, and finally history match and forecast two wells that are producing in the Vaca Muerta Shale.
Phase Behavior and Flow in Shale Nanopores From Molecular Simulations
Authors: Jin Zhehui , Firoozabadi Abbas
Published: September 2015

Phase behavior and flow in shale nanopores, due to fluid heterogeneity, cannot be described by bulk and continuum-based formulations. The interactions between fluid and rock molecules are important in both phase behavior and flow. As a result, frameworks from bulk equations of state in phase behavior, and Knudsen diffusion and Klinkenberg slippage in flow may not have direct applications. Recently, we have studied both phase behavior and flow in nanopores using various molecular simulations. This work addresses a number of issues in relation to phase behavior and flow in nanopores. We model the excess adsorption of ethane in shale media. The data of ethane adsorption has been reported recently. Past data on hydrocarbon adsorption is limited to methane. We also model the effect of water on hydrocarbon adsorption in kerogen and compare the results with the effect in clay. In flow, as in our recent work, we use the dual control volume-grand canonical molecular dynamics (DCV-GCMD) simulations. We use a low pressure difference between high pressure and low pressure reservoirs connected to the nanopores. We find that similar to our past work, the flux of methane in the slit pores can be two orders of magnitude higher than the results from the Knudsen diffusion.
Theoretical Investigation of the Effect of Membrane Properties of Nanoporous Reservoirs on the Phase Behavior of Confined Light Oil
Authors: Zhu Ziming , Yin Xiaolong , Ozkan Erdal
Published: September 2015

This theoretical study is a first effort to probe the effect of semi-permeable membrane properties of nanopore networks on hydrocarbon phase behavior in tight-oil reservoirs. It is considered that the fluids stored in a nanoporous reservoir are divided into two parts: one part that is already "filtered" and can flow to a production well without compositional change, and another part that replenishes the "filtered" fluid according to the membrane efficiency of the nanopore network and the prevailing filtration pressure. This selective hydrocarbon transport leads to a compositional change in both of the "filtered" and "unfiltered" parts and changes other oil properties accordingly. The compositional change, fluid density, viscosity and interfacial tension are calculated as functions of pressure when the pressure decreases below the bubble point pressure of the "filtered" part. The findings of this work have ramifications on fluid saturation distributions and the composition of the trapped fluids at the beginning of a potential EOR application.
A Thorough Investigation of Mechanisms of Enhanced Oil Recovery by Carbonated Water Injection
Authors: Sohrabi Mehran , Emadi Alireza , Farzaneh Seyed Amir , Ireland Shaun
Published: September 2015

The benefits and advantages of waterflood are well-known with many decades of application in a wide range of reservoirs with different crude oil and rock types. However, the average global recover factor for waterflood is only around 30%. There is, therefore, great interest in developing methods that can augment waterflood and improve its recovery factor from the current low values. It has been shown that enriching water with CO2 and injecting it in the form of carbonated water can improve the performance of water flood significantly 1-15. However, a complete understanding of the pore-scale interactions and events taking place during carbonated water injection (CWI) in an oil reservoir and the actual mechanisms by which additional oil may be recovered are still missing and therefore the true potential of CWI is not yet well known. This is further complicated by the fact that the current commercial reservoir simulators are not able to adequately simulate the complex and multi-physics processes that take place during CWI which include both fluid/fluid and rock/fluid interactions.

The objective of the Carbonated Water Injection (CWI) JIP at Heriot-Watt University is to perform a thorough investigation of the performance of CWI under reservoir conditions and systematically study the parameters that impact the amount of oil recovery by CWI and its underlying mechanisms. Here we present the results of a series of CWI experiments performed under reservoir conditions at pore-scale and core-scale. Direct flow visualisation results of our high-pressure micromodel experiments reveal very vividly the pore-scale events that take place as CO2 gradually leaves the injected carbonated water and dissolves in the oil. The results show that the pore-scale interactions of carbonated water with crude oil are quite different from the well-known mechanisms observed in conventional CO2 flood. Apart from the usual CO2-related mechanisms such as oil swelling and viscosity reduction, in CWI, formation of a new fluid phase within the oil is observed. As we will show, this is a major mechanism that significantly improves the performance of CWI and the amount of additional oil recovery achieved by CWI. Our coreflood experiments confirm our pore-scale flow visualization results and clearly show that, compared to conventional waterflood, CWI can lead to substantial additional oil recovery under both secondary mode (injected instead of conventional water flood) and tertiary mode (injected after conventional water flood). The performance of CWI is significantly affected by the composition of the oil including the amount of light and intermediate hydrocarbons dissolved (solution gas) in crude oil.
Investigating Nano-Fluid Mixture Effects to Enhance Oil Recovery
Authors: Tarek Mohamed
Published: September 2015

Nano-particles have been investigated in the last few years as a promising technique for enhanced oil recovery at laboratory scale. Different metal oxides nano-particles have been tested solely in previous papers and some of these nano-particles increased the ultimate oil recovery.

This paper investigates the effect of mixing more than one nano-oxide in one dispersing fluid (to form a nano-fluid) on the ultimate recovery. Three nano-oxides were selected: Aluminum oxide (Al2O3), Iron oxide (Fe2O3) and Silicon oxide (SiO2). The selection of these oxides was based on the percentages of additional recovery each nano-oxide provided in literature and the mechanism that caused this increase in recovery. Each oxide is believed to increase recovery through different mechanism and combining different oxides with different recovery enhancement mechanisms may lead to further increase in ultimate recovery.

Three reference core flooding runs were performed in order to check the effect of each nano-oxide on the experimental core plugs ultimate recovery after water flooding. Different single nano-fluids were injected in each core until no more oil was produced. The same mixture of nano-fluids was then injected in the three cores resulting in more oil production in all cases (thus validating our concept).

To understand the different effects these nano-fluids may have on recovery, several experiments were conducted. These tests included three experimental runs with different mixture concentrations of nano-particles on a high permeability core starting directly with tertiary recovery (no water flood was applied before injecting the nano mixture).

The outcomes of these experiments showed that nano-fluid mixtures could be used as a better technique for EOR than single nano-fluid. Optimum nano-fluid mixture cocentration depends on both fluid and rock properties. The use of different slugs with different nano-fluids seems to benefit the recovery.
Mathematical Model of a Well, Draining Fractured Reservoir
Authors: Sergey Durkin
Published: September 2015

Well tests are an integral part of learning the filtration characteristics of the producing formation. The article considers the main approaches of learning and interpreting the results of field research on stationary and non-stationary filtration mode. The choice of one or another mathematical model predictions depends on the quality of filtration properties interwell reservoir. Heterogeneous, low-permeability reservoirs are special problem for the study of the mechanism of filtration. In the attempt to create a mathematical model of a well draining fractured porous reservoir, based on a realistic representation of fractures. The results of the adaptation field research confirmed the efficiency of real well developed numerical model. Established model allowed to interpret the radial, linear and bilinear flow regime. It is shown that the reservoirs are characterized by a linear and bilinear flow regime, indicating that the filtering mechanism in the system of “matrix-fracture” by different laws filtering. Also it developed a methodical approach that allows to take into account the wellbore, given technological regime on the head and on the bottom of the well. Three-dimensional formulation of the problem has allowed to extend the model to the multiphase flow.
Full Resolution Full Field Simulation Using Localized Computations
Authors: Sheth Soham M.
Published: September 2015

Locality is inherent to all transient flow and transport phenomena. Superposition of the two disparate spotiotemporal scales that underlie flow and transport leads to the problem of dimensionality. While the spatial locality in the temporal evolution of state variables is well-studied, little is known about the locality that is present over the course of individual Newton iterations that arise in the solution of an implicit timestep. This work derives a priori sharp and conservative estimates for the Newton update before its corresponding linear system has been solved. The current focus is the sequential implicit procedure for general nonlinear and heterogeneous two-phase flow in multiple dimensions. Due to the analytical nature of the work, the estimates are independent of the underlying spatial discretization. There are numerous applications of these estimates, including their use towards characterizing the convergence rate of Newton's method as a function of timestep size, or towards the development of scalable linear preconditioning strategies. This work focuses on applying the estimates to reduce the size of the linear system that is to be solved at each Newton iteration.

The key to the derivation of these estimates is in forming and solving the infinite-dimensional Newton iteration for the semidiscrete residual equations. In an implicit simulator, the Newton updates are accurate approximations to the continuous in space infinitedimensional updates. While the infinite dimensional updates are obtained by solving linear PDEs analytically, the discrete approximations are obtained by inverting a linear system. For flow, the analytical estimate for the Newton update is the solution of a linear constant coefficient screened Poisson equation. For transport, the estimate is the solution of a first-order linear PDE. The analytical solutions for these estimates are derived, and they can be applied computationally to any discrete problem.

In a simulation, at each nonlinear iteration, the estimates are evaluated over parts of the domain and they are subsequently used to identify the unknowns and cells that will undergo a Newton update that is larger than any prescribed tolerance. The reduced linear system is then formed for these unknowns only, and is solved to obtain the Newton update. Since the estimates are conservative, there is no degradation of the nonlinear convergence rate.

We present comprehensive large-scale computational results. The performance improvement using the proposed method directly depends on the extent of locality present as dictated by the physics. For problems with slight compressibility, the localization of the linear systems results in an order of magnitude of improvement in computational performance. On the other hand, incompressible models involve global pressure updates, and the locality is exploited in the transport part only.
A Simulation Study of Enhanced Oil Recovery Using Carbon Dioxide Foam in Heterogeneous Reservoirs
Authors: Tham Su Li
Published: September 2015

Conventional gas flooding suffers from poor sweep efficiency in heterogeneous reservoirs. In absence of mobility control, gas preferentially travels through the path of least resistance, bypassing oil in low permeability areas. Stable foams restrict flow in high permeability channels, diverting some of the flow to the lower permeability layers and allowing injected fluid to contact oil that would have been unswept by conventional gas floods. The objective of this research was to determine the extent of improvement caused by use of foam for CO2 floods in a range of heterogeneous reservoirs. Moreover, this study aims to provide a qualitative understanding of foam in heterogeneous reservoirs, which would help in designing successful CO2 foam flooding in enhanced oil recovery projects. The simulation study involves two-dimensional reservoir models with varying reservoir heterogeneity modeled by different Dykstra-Parsons coefficients (VDP). A surfactant-alternating-gas (SAG) scheme and a water-alternating-gas (WAG) scheme were carried out to determine the improvement of using foam in SAG compared to conventional WAG where foam was not present. A waterflood was also carried out to determine the incremental oil recovery of SAG and WAG over waterflood.

The CO2 breakthrough times, recovery factors, and sweep efficiencies based on pore volume injected were calculated from CMG SATRS simulation results. These factors were improved across all heterogeneities when foam was present in the system; however, there were important differences. More stable foam was formed in the reservoirs with the lowest heterogeneity, as shown by the largest increase in injector bottomhole pressure for the reservoirs with the lowest VDP. The improvement in breakthrough time increased as reservoir heterogeneity increases. The breakthrough time was increased by 11.5% for reservoirs with the lowest VDP and 22.0% for reservoirs with the highest VDP. Foam lessened the severity of channeling and gravity segregation in reservoirs and improved vertical sweep. However, in the more heterogeneous cases, there were sections of the reservoir that remained unswept by CO2 even for SAG floods. The greatest improvement in terms of stock tank barrels of oil recovered from using SAG occurred for the most heterogeneous reservoirs. Compared to waterfloods, SAG floods recovered an additional 41.2% of OOIP on average, which was 4.5% OOIP more than conventional WAG floods. Thus, the use of foam was more economical in reservoirs with greater heterogeneities.