bluuebunny/crossref_metadata_2025 huggingface dataset:
Liquids Rich Organic Shale Recovery Factor Application
Authors: Barba Robert E.
Published: September 2015

Recovery factor analysis involves the integration of hydrocarbon pore volume from a core calibrated petrophysical analysis with the estimated ultimate recovery from the lateral wellbore. A key benefit is the normalization of performance among wellbores with varying oil in place volumes and establishment of “best practices” for well completions. A secondary benefit is a method to obtain production performance estimates for various landing zone options prior to drilling the lateral. Lastly, a comparison of recovery factors for various assumptions of producing height can provide a “reality check” on how much of the vertical pay column is connected to the wellbore via propped or unpropped conductivity. Initial results from analysis of over 150 Wolfcamp and Cline wells indicated an average recovery factor of 8.2% for 160 acre drainage areas. The performance study suggests that the producing heights in these low modulus formations are limited primarily to the propped height with limited unpropped height. This is a significant finding in that propped height from tracer surveys is limited to 50 to 60 ft regardless of the fluid type pumped with resultant producing heights of 100–150 ft when unpropped height is considered. The unpropped height estimate was made from a correlation to recovery factors. While normally propped heights can be improved in conventional reservoirs with gelled fluids, the higher viscosity fluids are shown to be ineffective at increasing propped heights in organic nanodarcy shales due to the large disconnect between break and closure times. Recommendations are provided to determine “best practices” to economically increase producing height, ideally with generic completion procedures using normal hybrid slickwater/borate systems. One option proposed is the use of coiled tubing to deliver the treatment via the annulus and then clean out the subsequent bridge plug location following a traditional “forced closure” procedure in the lateral to close the fracture prior to excessive proppant settling. Another option being discussed is the use of lightweight proppants, however the unit cost will need to be significantly reduced to make this an economic option due to the large proppant volumes required in shales. With lightweight proppants the volumes are reduced significantly due to the difference in specific gravity, however at the high unit cost this would still increase the stage cost by a factor of three. There are several other recently released products that have the potential to improve propped height and these should be thoroughly evaluated before dismissing them given the significant upside that exists. In many shale plays the gross pay thickness is well in excess of the expected conductive height and the ability to contact more vertical section should translate into significantly better production rates that may help justify the increased investment. The study should encourage additional research to be conducted in this area.
Modeling Low Salinity Waterflooding in Mineralogically Different Carbonates
Authors: Qiao Changhe , Johns Russell , Li Li , Xu Jinchao
Published: September 2015

Injection of low salinity brines can improve oil recovery (IOR) in carbonate reservoirs by changing the rock wettability from oil-wet to more water-wet. Existing numerical simulation models for low salinity flooding use empirical relationships that do not properly capture important processes for wettability alteration, such as aqueous species concentrations, oil acidity, and rock mineralogy. In our previous research on modeling spontaneous imbibition with tuned water (SPE170966), we developed a process-based and predictive model that explicitly includes the chemical interactions between crude oil, brine, and the carbonate surface. In this research, we extend the previous model for low salinity water flooding to both chalk and limestone cores.

We examine the role of mineralogy in low salinity waterflooding by developing a mechanistic model for wettability that includes surface complexation, aqueous reactions, and dissolution/precipitation of calcite and anhydrite. The reactions coupled with the equations of multiphase flow and transport are solved simultaneously using an IMPEC in-house simulator, PennSim. Relative permeability functions and residual oil saturation during flooding are adjusted dynamically according to the concentration of oil acids attached to the mineral surface. Core flooding experiments from the Stevns Klint (SK) chalk (Fathi et al. 2010), a limestone with small amount of anhydrite (Austad et al. 2012), and a Middle Eastern carbonate with 6% volume fraction anhydrite (Yousef et al. 2011) are used to tune the reaction network and make recovery predictions. Simulation results give remarkable agreement with the effluent concentrations of SO42−, Ca2+ and Mg2+ reported from chromatographic wettability tests and the recoveries for injection of various brines into chalk and limestone cores of differing compositions. For SK chalk without anhydrite, reducing the Na+ and Cl– concentration of seawater, while keeping SO42− (sulfate) leads to improved oil recovery (IOR) by as much as 6% OOIP. The presence of anhydrite, which provides a natural source of sulfate, also significantly increased oil recovery for injection of diluted formation water and seawater. Simulations of 2D five-spot patterns using tuned reaction networks demonstrated that IORs from 5% to 20% OOIP can be obtained at reasonable values of pore volumes injected (2.0 PVI). These IORs depend greatly on the aqueous chemistry of the injected fluid, and sweep. The results highlight the critical importance of understanding the mineralogy and including a mechanistic reaction model in the simulation of low salinity water floods.
Tie-Line Solutions for MMP Calculations By Equations-of-State
Authors: Khorsandi Saeid , Johns Russell T.
Published: September 2015

Minimum miscibility pressure (MMP) is one of the most important parameters in the design of successful gas floods. One technique for calculation of MMP uses the analytical method based on the method of characteristics (MOC). Although MOC is the fastest MMP calculation method available today, it can suffer from robustness owing to complex phase behavior observed in some field displacements. The current MOC method implemented in commercial software assumes that the composition route is composed of a series of shocks from one key tie line to the next. For some displacements, however, these key tie lines do not control miscibility and significant errors in MMP can result. One way to eliminate the error lies in constructing the entire composition route, which is challenging for many complex multicomponent oil displacements.

This paper examines how to determine the unique composition route for all conceivable phase behavior complexities, making the MOC method for MMP calculation significantly more robust. The approach relies on solving for all tie lines in the composition route directly, independent of fractional flow. MMP estimation is based solely on the tie-line route calculation in tie-line space, where both tie-line rarefactions and shocks may exist. MMPs that result from 1-D displacements of oil by gas are therefore decoupled from fractional flow, making the calculation significantly easier and more robust. Once tie lines in the composition route are determined, specific compositions for a given fractional flow can be mapped onto the tie-line solution, completing the composition route if desired. Compared to current methods, the formulation in tie-line space has a smaller rank, few or no umbilic points, and as stated is independent of fractional flow. Example solutions show that MMPs are easily calculated with this approach for complex displacements that were incorrectly or very difficult to solve before, including multicomponent gas injection with bifurcating phase behavior.
A Robust Automatic Dip Picking Technique to Improve Geological Interpretation and Post-Drill Formation Evaluation of Azimuthal Wellbore Image Logs
Authors: Ye Shin-Ju
Published: September 2015

Automatic dip picking avoids the disadvantages of hand picking (subjective, time-consuming, and ergonomically unfriendly); in particular, it reduces dip uncertainty for low-resolution borehole images. Many automatic dip picking methods have been developed since the 1950's. Each of these methods is tied to a specific type of tool (e.g., dipmeter tools or partial-wellbore-coverage pad-type imagers), and they are unreliable to process high-angle and horizontal (HAHz) wellbore azimuthal image data.

This article presents a new method to detect dips in HAHz borehole images. Although this method was originally designed for full wellbore azimuthal images, it is applicable to any dipmeter and pad-type image logs. The proposed automatic dip picking method is simple, yet robust. It consists of the following three main steps: first, determine an optimal sinusoidal trend on the image at each depth using a minimum-variance technique; second, compute the contrast at each depth along the optimal sinusoidal line on the gradient (or first-derivative) image; and finally, locate bedding surface boundaries at depths with the highest contrasts.

This method emulates the human pattern recognition process by first observing overall global image sinusoidal trends, and then examining detailed local bed contrasts to locate the bed boundaries. Conventional pattern fitting methods using edge detection and Hough transform (or sinewave fitting) can be unreliable and greatly affected by the noise and artifacts on the image, as these methods focus immediately on detailed and localized image features, and often overlook global image patterns.

Although other correlation techniques have been tested, the minimum-variance method is the preferred approach, for it generates the most consistent sinewaves. It correlates all azimuthal bins simultaneously and is much more reliable than two-curve correlation methods. Since the variances are calculated along sinusoidal lines, there is no need to perform individual sinewave fitting.

The minimum-variance method combines the conventional, complicated, two-step dipmeter processing methodology (first curve correlation, then sinewave fitting) into one single step to determine an optimal local sinewave. With fewer steps, there are fewer scenarios and problems to consider and fewer parameters to adjust. Moreover, at each depth, the minimum-variance method can find the optimal sinewave within a full range of search parameters (sinusoid amplitude and phase). It can identify faults if visible, as well as reversed sinewaves in “bulls-eye” sections where the wellbore axis is almost parallel to the bedding planes.

The proposed method has been applied to many logging-while-drilling density images and dipmeter data from fields worldwide. It has substantially reduced the interpretational time in building earth models from image logs for logging tool response modeling in petrophysical evaluation.
Predicting Gas Apparent Permeability of Shale Samples: A Novel Analytical Approach
Authors: Kazemi Mohammad , Borujeni Ali Takbiri
Published: September 2015

Natural gas production of the United States from shale resources increased from 4 percent of total gas production in 2005 to 40 percent in 2012. These resources are different from conventional hydrocarbon resources due to the presence of extremely tight organic pores and low permeabilities. Presence of the nanopores may cause rarefaction effects, especially in laboratory conditions, which increases the effects of temperature and pressure on the apparent permeability of shale samples. In order to determine the permeability of these resources, laboratory measured apparent permeabilities, if conducted in low pressure and temperature, need to be extrapolated to reservoir conditions. In addition, gas flow in low pressures has important applications in predicting the gas production rates from unconventional reservoirs.

Analytical methods for estimating gas apparent permeability (AP) of shale have been already proposed, e.g. Navier-Stokes and Advective -Diffusive Models (ADM); however, they are valid for a limited range of Knudsen numbers (Kn < 0.5) and they have oversimplifying assumptions that overestimate the mass flux (or permeability) of nanopores. In addition, their results do not show the effect of temperature and gas molecular weight on AP.

The presented work aims to develop an analytical model for gas apparent permeability of nanopores which is valid for Knudsen number up to unity. Solutions to the Regularized 13 (R13)-moment equations (extension of Grad's 13-moments equations) provide a reliable tool to derive an analytical model for gas AP in nanotubes. The novelty of this work is that we provide an analytical model for gas AP which is valid for higher range of Knudsen numbers (by comparing with the kinetic data) in contrast to the previously developed analytical models. The new model is used to predict the impact of controlling parameters such as temperature, pressure, molecular weight, pore size, and Tangential Momentum Accommodation Coefficient (TMAC) on gas AP. It is shown that the gas molecular weight and temperature have significant effect on gas apparent permeability at low pressures. The effect of adsorption on AP of nanotubes is studied by employing the experimental Langmuir isotherms of different shale samples.

The bundle of tubes method is used to compare R13 AP model with the experimental data of a Marcellus shale core plug. The model's AP results for Nitrogen and Carbon Dioxide agree with the experimental measurements.
A Multi-Pass Procedure for Redistributing Linearized Mass Balance Errors to Improve Simulator Performance
Authors: Wang Qinghua , Fleming Graham , Gu Zhiqiang
Published: September 2015

In a generalized reservoir simulator for compositional and black oil models, the primary governing equations are mass conservation equations and volume balance equations with pressure and component masses as the primary unknowns. The phase equilibrium is honored in the calculation of partial volume derivatives. The Newton-Raphson method is widely chosen to solve this non-linear system: the equations are first linearized then solved using direct or iterative linear solvers. Direct solvers are not practical for large systems; therefore, iterative solvers are used. Iterative solvers are not exact and are usually converged to a specified criterion. The stricter the criterion, the higher the computational effort required by the linear solver. On the other hand, a loose convergence criterion can lead to more Newton iterations or false physical solutions.

In addition to the convergence tolerances for linear solvers, certain criteria must be applied to the non-linear Newton iterations. One of the main convergence criteria is that the volume error at any gridblock is less than a small fraction of its pore volume. The linear solver tolerance should be somehow related to this non-linear tolerance, or the linear solutions should be adjusted to help the convergence of the non-linear iterations. Because of the limited accuracy of iterative linear solvers, a two-pass procedure is proposed to improve the linear solutions by redistributing linearized mass balance errors. In the first step, all the gridblocks are divided into different groups according to whether the mass change is positive or negative and by the magnitude of contribution to local fluid volume change. Then a constrained optimization problem is defined and solved to adjust the linear solutions, satisfying global mass conservation. With these modified solutions, the linearized volume errors for all the gridblocks are calculated. In the second step, a criterion similar to the aforementioned volume convergence criterion for Newton iteration is imposed on the linearized volume error for each gridblock. With reasonable linear solutions, most of the gridblocks should satisfy this criterion. For gridblocks that do not satisfy this condition, another constrained optimization problem is defined to ensure local volume balance with local mass solutions further adjusted. With this two-pass procedure, global mass conservation and local volume balance are achieved for the implicit formulation of the governing equations, with little or no degradation of the Newton convergence, and usually without needing to tighten the linear solver convergence tolerances.
Value of Information of Frequent Time-Lapse Seismic for Thermal EOR Monitoring at Peace River
Authors: Przybysz-Jarnut J. K. , Didraga C. , Potters J. H. , Lopez J. L. , La Follett J. R. , Wills P. B. , Bakku S. K. , Xue Y. , Barker T. B. , Brouwer D. R.
Published: September 2015

Time-lapse seismic surveillance is a proven technology for areal conformance monitoring offshore, but not onshore due to its high cost and typically poor data quality in that environment. Yet a number of examples in the industry show that non-uniform reservoir sweep is common in IOR and EOR projects and, if not addressed, it can significantly reduce ultimate recovery. In such projects the efficacy of injectants such as water, steam, gas, and solvents needs to be maximized to reduce cost and environmental footprint. This requires that we know what happens in-between wells, and for this purpose we conducted a pilot of high fidelity frequent seismic monitoring of thermal EOR re-development in one of the production pads in the bitumen deposits in Peace River, Canada. We detected patterns that can be directly linked to dynamic reservoir changes on a weekly or more frequent basis, such as pressure increase during injection, fluid phase changes, and connection to previously stimulated zones. The data also highlight the imprint of previous operations on the reservoir state prior to the current re-development, stressing the challenges faced when managing steam conformance. Our observations indicate that frequent time-lapse seismic images significantly contribute to determining injection/production strategy adjustments aimed at improved areal steam conformance.
Computation of Apparent Formation Dip From Single Azimuth Sensor Data Having Different Depths of Investigation
Authors: Stockhausen Ed , Rasmus John , Bammi Sachin
Published: September 2015

A typical gamma-gamma density tool used for making borehole geophysical measurements has a source and two in-line detectors at different distances from the source which results in each having unique effective penetration lengths (EPLs). Gamma-gamma tools typically have internal shielding so that the measurement is primarily influenced by the formation directly in front of the detectors. In high angle and horizontal wells, the difference in EPL creates an offset in measured depth (MD) between the two measurements when crossing a boundary between two layers having a density contrast. In a wellbore drilling down-section with the logging tool oriented toward the bottom of the wellbore, the detector with the deeper EPL senses the boundary at a shallower measured depth while the shallower-sensing one senses the boundary at a deeper measured depth. For a wellbore drilling up-section, the detection order and measured depths are reversed. This effect has been verified using Monte-Carlo N-Particle (MCNP) modeling code (Radtke 2006).

This offset in measured depth is a function of the relative difference in EPL, the azimuthal orientation/relative bearing of the detectors with respect to top of hole, and the relative angle between the wellbore and the formation boundary. By knowing the respective tool EPL's and the relative bearing of the detectors, and measuring/determining the offset in measured depth where the detectors have responsed to the bed boundaries, the incident angle or angle of attack can be calculated. The depth shifts can be calucaled by auto-correlation techniques or manually. The incident angle can be combined with the trajectory inclination to compute the apparent formation dip in the azimuth of the wellbore.

The incident angle gives us the indication of whether we are drilling up-section or down-section and how quickly we are cutting through the beds. These are a critical factors when determining the position of the wellbore relative to the geological layers while geosteering or when doing post drill look backs (correlation studies) and attempting to determine where the well was placed. A sinusoid fitting technique is typically used with azimuthal image data to determine formation dip and azimuth. The advantage of the new method is that sinusoids are not required. Only two or more single, oriented nonrotating measurements are needed. The method is validated with a full azimuthal density data set and then demonstrated in a second well with a commercial density logging tool that is conveyed through-the-bit. These tools are designed such that the density pad faces downward toward the bottom of the hole during logging operations and is not rotated azimuthally. Since azimuthal data is not acquired, one limitation of the technique is that the azimuth of the formation boundary cannot be computed.
A New Perspective on Applying a Conformance Lookback Analysis for the Central Permian Basin Fields
Authors: Hinds C. , Sayarpour M. , Hameed A.
Published: September 2015

As improved oil recovery activities increases in a field, premature break-through of injected water/gas continue to pose conformance control challenges in reservoir managment. A proactive conformance program is required to address rapid increase of water-oil and/or gas-oil ratios, maintain an effective sweep efficiency and minimize the risk of loss of containment to name a few. The purpose of the Central Permian Conformance Project (CPCP) team was to objectively evaluate the past conformance treatments, causes of their successes or failures, and implement lessons learned to identify possible solutions which improve oil recovery in MCBU's Central Permian assets.

The fields analyzed were clastic and carbonate reservoirs. Both fields provided unique sets of challenges and solutions. Production in the clastic field is from multilayer zones while in the other reservoir there are no distinctive zone separations. The conformance issues in these fields are due to highly permeable layers, extensive fracture networks or vugs.

The Central Permian Conformance Project was divided into three phases: 1) Performed lookback analysis on previous conformance jobs; 2) Use standardized workflows to identify existing conformance issues and solutions; and 3) piloting or fieldwide implementation. This paper focus on part one as the other two phases will be discussed in future publication.

The main focus of this analysis was phase 1 involving lookback analysis of previous conformance control jobs performed. From 1980 to 2013, there were a total of 110 patterns where conformance controls were executed primarily utilizing MARCITSM gel. To have an objective definition of success or failure, a Spotfire® dashboard was created to systematically compare incremental oil production and decline rates before (6 months prior) and after (24 months succeeding) a conformance job.

Lookback analysis on clastic and carbonate fields indicated: Numbers of successful jobs are meaningfully higher in fractured areas compared to less-fractures areas in analyzed fields Low success rates occurred mainly in the more homogenous area or where major fractures are absent, and/or permeability contrast is low A successful conformance improvement is dependent on correct identification of the problem, usage of the appropriate gel, proper placement and slug size as well as a proactive surveillance plan Other chemicals, such as CO2 foam gel and cross-linked polymers were also evaluated and showed promising results

Based on the lookback analysis, this paper will discuss the systematic data driven approach to evaluate incremental gain or loss of production and use lessons learned to address and emphasize on a systematic approach to select pattern and zone, chemical used and proper designed volume.
Modeling of Transport Properties Using the SAFT-VR Mie Equation of State
Authors: Gonzalez Alfonso , Pereira Luis , Paricaud Patrice , Coquelet Christophe , Chapoy Antonin
Published: September 2015

Carbon capture and storage (CCS) has been presented as one of the most promising methods to counterbalance the CO2 emissions from the combustion of fossil fuels. Density, viscosity and interfacial tension (IFT) are, among others properties, crucial for the safe and optimum transport and storage of CO2-rich steams and they play a key role in enhanced oil recovery (EOR) operations. Therefore, in the present work the capability of a new molecular based equation of state (EoS) to describe these properties was evaluated by comparing the model predictions against literature experimental data.

The EoS considered herein is based on an accurate statistical associating fluid theory with variable range interaction through Mie potentials (SAFT-VR Mie EoS). The EoS was used to describe the vapor-liquid equilibria (VLE) and the densities of selected mixtures. Phase equilibrium calculations are then used to estimate viscosity and interfacial tension values. The viscosity model considered is the TRAPP method using the single phase densities, calculated from the EoS. The IFT was evaluated by coupling this EoS with the density gradient theory of fluids interfaces (DGT). The DGT uses bulk phase properties from the mixture to readily estimate the density distribution of each component across the interface and predict interfacial tension values.

To assess the adequacy of the selected models, the modeling results were compared against experimental data of several CCVrich systems in a wide range of conditions from the literature. The evaluated systems include five binaries (CO2/O2, CO2/N2, CO2/Ar, CO2/n-C4 and CO2/n-C10) and two multicomponent mixtures (90%CO2 / 5%O2 / 2%Ar / 3%N2 and 90%CO2 / 6%n-C4 / 4%n-C10).

The modeling results showed low absolute average deviations to the experimental viscosity and IFT data from the literature, supporting the capabilities of the adopted models for describing thermophysical properties of CO2-rich systems.
Fly Ash Nanoparticle-Stabilized CO2-in-Water Foams for Gas Mobility Control Applications
Authors: Singh Robin , Gupta Abhay , Mohanty Kishore K. , Huh Chun , Lee Daeyang , Cho Heechan
Published: September 2015

The goal of this work is to develop a novel way of beneficially utilizing two main waste products from coal power-generation plants – carbon dioxide and fly ash – by generating fly ash nanoparticle-stabilized CO2 foam for CO2 EOR mobility control. First, as the grain size of fly ash is generally too large for injection into reservoirs, it was reduced to nano-size by the ball-milling process. Second, dispersion stability analysis was performed to evaluate a suitable dispersing agent for fly ash nanoparticles (FA-NP). A range of surfactants (anionic, cationic, and non-ionic) was used in dilute concentrations. Surfactants were screened based on particle-hydrodynamic diameters and polydispersity index of the dispersion as measured by dynamic light scattering. Third, foam flow experiments were performed using combinations of FA-NP and various surfactants. Aqueous foam was created in-situ by coinjecting the FA-NP and/or surfactants with liquid CO2 through a sandpack at a fixed foam quality. Foam texture, as seen in the view-cell, was used to screen suitable surfactants that stabilized strong foams. Finally, the foam flow experiments were conducted in a Berea sandstone core. Pressure drop across the core was measured to estimate the achieved foam resistance factor and the apparent viscosity of the generated foam. Nano-milling and thermal treatment processes were able to yield thermally-treated fly ash (TTFA) nanoparticles with an average size of 180 nm. Dispersion stability analysis revealed that anionic and non-ionic surfactants are suitable in dispersing these nanoparticles. Foam texture visualization demonstrated that strong carbon dioxide-in-water foam/emulsion with fine texture can be generated using TTFA nanoparticles in porous media in conjunction with a non-ionic surfactant or an anionic surfactant in dilute concentrations. Foam flow experiments in a Berea core showed that TTFA nanoparticles even in low concentrations (0.4 wt%) can significantly improve the foam stability and foam resistance factor of an anionic surfactant (in the absence of oil). Antagonistic effects were observed in foam stability in Berea core by addition of TTFA nanoparticles to nonionic surfactants. This study has the potential of not only to minimize the surfactant usage for foam-based CO2 EOR mobility control, but also to sequester both CO2 and fly ash in subsurface formations.
A New Analysis on the Convective Heat Transfer at the Edge of the SAGD Chamber
Authors: Li Qingmao , Chen Zhangxin
Published: September 2015

Heat transfer is an imperative mechanism in the SAGD (steam assisted gravity drainage) process for bitumen production. A better understanding of the heat transfer process is critical for a successful SAGD project design. Following the work of Butler (1981, 1985 and 1997), the conduction only assumption has been widely used. However, there have been some studies indicating the importance of convection heat transfer at the edge of a SAGD chamber.

Based on analysis of physical heat transfer mechanisms in the SAGD process, an improved analytical model is developed in this study to calculate the condensate velocity and heat transfer considering both conduction and convection. First, heat transfer at the edge of a steam chamber is analyzed to understand the role of condensate flow and steam chamber interface movement. Three possible cases are proposed to analyze the relationship between the energy left behind the front because of the steam chamber interface movement and the energy carried into the cold reservoir by the condensate flow in the SAGD process. Based on the heat balance analysis and available temperature-saturation relationship, a modified condensate velocity normal to the interface of a SAGD chamber is proposed. It is assumed that the condensate velocity is proportional to the steam chamber interface movement velocity, the fluid mobility ratio of reservoir to steam chamber interface, and the volume heat capacity ratio of reservoir to steam condensates. This new velocity is used to investigate the convection role in the heat transfer of the SAGD process. Moreover, heat transfer equations are solved by using constant heat flow (or Robin) boundary condition to verify the widely-used constant temperature (or Dirichlet) boundary condition at the edge of the steam chamber. The newly developed model is validated by calculating and comparing the condensate velocity normal to the interface, apparent thermal diffusivity and heat fluxes ahead of the steam chamber with filed data (Dover UTF Phase B, Athabasca Reservoir). It is shown that convection can provide a larger contribution to heat transfer than conduction at the edge of a steam chamber, but drops rapidly over a short distance normal to the interface. Considering a large convective heat flow at the edge of the SAGD chamber, temperature can be thought as a constant with minor error.

The developed theory provides a quick prediction of apparent thermal diffusivity, temperature distribution, heat fluxes considering both conduction and convection for the design of SAGD projects. Furthermore, it offers a simple formula to show connection between the condensate velocities normal to a chamber interface and the movement velocity of the chamber interface, which can be applied to any thermal processes with steam chamber expanding.
Fractured Volcanic Reservoir Characterization: A Case Study in the Deep Songliao Basin
Authors: Sun Desheng , Zhang Feng , Gao Jun , Xi Xiaoyu , Lin Jixiang
Published: September 2015

Based on the integrated acquisition and processing of 3D-VSP and full-azimuth surface seismic data, this paper focuses on the interpretation of volcanic reservoirs to characterize the fractured volcanic reservoir geometry, distribution, properties and highly productive gas regions.

The area of interest is located in the deep Songliao basin of north-eastern China. The area characterized by a monoclinal structure that includes a few fractured volcanic reservoir traps in Cretaceous formations. The P&D of gas reservoirs faced many difficulties, including imaging of the volcano, identification of heterogeneous volcanic rock facies, and fracture detection, which was the most important.

Use of seismic attributes for fractured volcanic reservoirs detection below the resolution of conventional seismic data is a major goal in this project. A method is developed to improve imaging of volcanoes, and minor faults and fractures using “discrete frequency curvature (DFC)”. The DFC data are computed using discrete frequency seismic data obtained from spectral decomposition. The DFC attribute allows us to recognize different geologic information about fractured volcanic reservoirs in different frequency bands of seismic data. The low-frequency curvature data can be used to recognize the distribution of volcanoes, whereas high-frequency curvature data is more effective at detecting minor faults and fractures. Moreover, the multi-geophysical methods, such as strata slice, HTI fracture detection and pre-stack inversion etc., also have been applied to characterize the volcanic reservoir. Strata time slices of coherence data are used to describe the volcanic evolution and volcanic rock facies. Structure modelling can provide an efficient tool to delineate geometry and distributions of volcanic bodies. The fracture inversion and HTI fracture detection method can be used to detect the orientation and density of fractured reservoir, while pre-stack inversion is applied to detect gas-bearing volcanic reservoirs.

After integrated study of the seismic attributes, well logs, and production data, we calculated porosity, permeability, net thickness and predicted the favourable production zones of the volcanic reservoir. The main factors controlling the volcanic reservoir are the distribution of volcanoes, volcanic rock facies, small faults, and fractures. The hydrocarbon reservoirs are located at a high position within the volcanoes, and the hydrocarbon is also clustered around the small faults and fractures within the system. Three horizontal wells were drilled based on the results of this study and very productive in the regions that were predicted to be enriched in hydrocarbons.

The results of our case study show DFC attribute has the potential to be a highly effective and very valuable seismic method.
Reservoir Rock Characterization Using Centrifuge and Nuclear Magnetic Resonance: A Laboratory Study of Middle Bakken Cores
Authors: Karimi Somayeh , Saidian Milad , Prasad Manika , Kazemi Hossein
Published: September 2015

In tight liquid-rich shale formations, fast and accurate techniques to determine reservoir key parameters, such as oil and water end-point saturations, capillary pressures, relative permeabilities, and pore-size distribution (PSD) are of great interest. In this paper, we use centrifuge and nuclear magnetic resonance (NMR) to determine these parameters for several Bakken cores. First, we measured helium porosity and Klinkenberg permeability of clean and dry Middle Bakken core plugs. After saturating these core plugs with brine, we performed drainage measurements using a high-speed centrifuge. Before and after centrifuge experiment, we measured the transverse relaxation time (T2) with a 2-MHz NMR instrument for use for pore-size distribution. Our results indicate that, using both centrifuge and NMR, we can obtain important petrophysical information for use in reservoir engineering and numerical simulation applications.
Improving Performance of the Phase Equilibrium Calculations in the Surface Network Portion of an Integrated Reservoir Simulator/Surface Network Compositional Model
Authors: Gu Zhiqiang , Wong Terry , Ma Jie
Published: September 2015

A network model can be extremely sophisticated for some miscible gas injection simulations. Sometimes, miscible gas injection, gas cap reinjection, and gas lift within the network are required to be solved simultaneously with a reservoir model. The phase equilibrium calculation for a network can consume a significant proportion of the total central processing unit (CPU) time. Equation of state (EOS) -based phase equilibrium can be divided into single-phase and two-phase calculations. Most research focuses on reducing the number and computational cost of EOS equilibrium calculations for reservoir modeling. Improving the performance of the phase equilibrium calculation for network flow is rarely discussed in the literature.

This paper describes methods applied to speed up the network calculations. The entire network is represented as a series of nodes and connections between nodes. It can be divided into several segments. If there is no introduction of other fluids from connecting segments, the overall composition is constant within a particular segment. Based on information from the previous phase status of each node or current phase status of up/downstream nodes, the nodes with a phase status change can be identified by regular single-phase stability analysis and flash calculation methods. Therefore, the segments can be divided into several single gas/oil and two-phase regions. For the nodes within two-phase regions, some correlation models can be applied to calculate equilibrium constant K-values for each component. Then, the flash calculation can be performed using the Rachford-Rice procedure. For single-phase regions, a phase envelope generation approach is used. A saturation pressure calculation is performed at a low value of pressure and temperature. Then, several points on the rest of the curve are extrapolated sequentially in a multistage extrapolation. If the temperature of a node is between two temperatures where an approximate value of the saturation pressure was identified, interpolation can be used to estimate the saturation pressure for this node.

A benchmark of example problems demonstrates that this approach can significantly speed up both single-phase stability tests and two-phase flash calculation with little accuracy loss. Phase equilibrium calculation is usually intensive in terms of CPU time. This paper designs a multistep procedure to identify the phase status along pipes. The improvement of computational efficiency in the phase equilibrium calculations within the surface network flow simulation can reduce the overall simulation CPU time and make it practical to run a full-field miscible gas injection model.
Effect of Large Capillary Pressure on Fluid Flow and Transport in Stress-sensitive Tight Oil Reservoirs
Authors: Xiong Yi , Winterfeld Phil , Wang Cong , Huang Zhaoqin , Wu Yu-Shu
Published: September 2015

The pore sizes of unconventional reservoir rock, such as shale and tight rock, are on the order of nanometers. The thermodynamic properties of in-situ hydrocarbon mixtures in such small pores are significantly different from those of fluids in bulk size, primarily due to effect of large capillary pressure. For example, it has been recognized that the phase envelop shifts and bubble-point pressure is suppressed in tight and shale oil reservoirs. On the other hand, the stress-dependency is pronounced in low permeability rocks. It has been observed that pore sizes, especially the sizes of pore-throats, are subject to decrease due to rock deformation induced by the fluid depletion from over-pressurized tight and shale reservoirs. This reduction on pore spaces again affects the capillary pressure and therefore thermodynamic properties of reservoir fluids. Thus it is necessary to model the effect of stress- dependent capillary pressure and rock deformation on tight and shale reservoirs.

In this paper, we propose and develop a multiphase, multidimensional compositional reservoir model to capture the effect of large capillary pressure on flow and transport in stress-sensitive unconventional reservoirs. The vapor-liquid equilibrium (VLE) calculation is performed with Peng-Robinson Equation of State (EOS), including the impact of capillary pressure on phase behavior and thermodynamic properties. The fluid flow is fully coupled with geomechanical model, which is derived from the thermo- poro-elasticity theory; mean normal stress as the stress variable is solved simultaneously with mass conservation equations. The finite-volume based numerical method, integrated finite difference method, is used for space discretization for both mass conservation and stress equations. The formulations are solved fully implicitly to assure the stability.

We use Eagle Ford tight oil formations as an example to demonstrate the effect of capillary pressure on VLE. It shows that the bubble-point pressure is suppressed within nano-pores, and fluid properties, such as oil density and viscosity, are influenced by the suppression due to more light components remained in liquid phase. In order to illustrate the effect of stress-dependent capillary pressure on tight oil flow and production, we perform numerical studies on Bakken tight oil reservoirs. The simulation results show that bubble-point suppression is exaggerated by effects of rock deformation, and capillary pressure on VLE also affects the reservoir pressure and effective stress. Therefore the interactive effects between capillary pressure and rock deformation are observed in numerical results. Finally, the production performance in the simulation examples demonstrates the large effect of large capillary pressure on estimated ultimate recovery (EUR) in stress-sensitive tight reservoirs.
Quantifying Electrical Resistivity of Isolated Kerogen from Organic-Rich Mudrocks using Laboratory Experiments
Authors: Firdaus Gama , Heidari Zoya
Published: September 2015

Reliability of conventional resistivity-porosity-saturation models (e.g., dual water and Waxman-Smits) is questionable in organic-rich mudrocks, which often leads to overestimation of water saturation. Previous publications showed that the interpretation of electrical resistivity logs for such rocks is challenging because of the presence of highly mature kerogen and pyrite connected networks that can influence electrical resistivity measurements. However, the electrical properties of kerogen in these rocks have not yet been quantified experimentally. Separation of kerogen from mudrocks and subsequent removal of pyrite from the kerogen, both requirements for successful laboratory experiments, remain challenging. In this paper, we quantitatively evaluate the electrical resistivity of mature kerogen using an experimental approach.

We first isolated kerogen from mudrock samples, using physical and chemical techniques and removed pyrite by treating the sample with acidic chromium chloride solution under nitrogen (N2) atmosphere. The isolated kerogen powder sample is then compressed to form a homogeneous consolidated disk using a mold frame designed for this purpose. Furthermore, we synthetically matured both mudrock and isolated kerogen samples by heat-treating. Then, we measured the electrical resistivity and geochemical properties of each set of molded samples at different maturity levels. The actual electrical resistivity of kerogen was estimated by minimizing the difference between the numerically simulated and measured effective electrical resistivity of the molded kerogen samples.

We successfully isolated kerogen from Haynesville and Eagle Ford mudrock samples. X-ray fluorescence (XRF) measurements confirmed the absence of carbonates, silicates, and pyrite in the isolated kerogen samples. We observed a significant decrease in electrical resistivity of isolated kerogen samples from the Haynesville (i.e., up to four orders of magnitude) and the Eagle Ford (i.e., up to nine orders of magnitude) formations upon elevating the heat-treatment temperature from 300°C to 800°C. The decrease of electrical resistivity at high maturity levels could be attributed to the presence graphite-like sheets and/or appearance of aromatic components in the organic matter. The outcomes of this paper can potentially improve interpretation of electrical resistivity logs in organic-rich mudrocks, which can lead to enhanced well-log-based assessment of in situ hydrocarbon saturation.
Nuclear Magnetic Resonance Investigation of Surface Relaxivity Modification by Paramagnetic Nanoparticles
Authors: Zhu Chunxiao , Daigle Hugh , Bryant Steven
Published: September 2015

Nuclear magnetic resonance (NMR) measurements are routinely used to characterize pore size distributions in fluid saturated porous media. The principle of the NMR measurement is that the result is linked with pore size by a parameter named surface relaxivity. However, in natural porous media, surface relaxivity is not constant or well-known due to heterogeneous distributions of impurities on pore surfaces. To control pore surface relaxivity, we injected paramagnetic zirconia nanoparticles into silica porous media: glass bead packs and sandstone core samples. Adsorption of the nanoparticles onto the pore surfaces altered their surface relaxivity due to differences in relaxivity between the silica surfaces and the nanoparticles. NMR measurements of porous media saturated with zirconia nanoparticle dispersions and deionized (DI) water were compared to calculate amount of adsorbed zirconia nanoparticles and quantify the alteration of pore surface relaxivity. Our results indicate that adsorption of nanoparticles onto pore surfaces leaves fewer nanoparticles in dispersion within the pore space and alters surface relaxation on pore wall with attached nanoparticles. The overall relaxation rate of the porous medium is thus affected by adsorption, which changes the surface relaxation rate and the relaxation rate of the fluid within the pore space. Electrostatic interactions drive nanoparticle adsorption onto pore walls. When silica porous media, which have negative surface charge, are saturated with positively charged nanoparticles, the nanoparticles adsorb onto the pore surface. When the porous media are saturated with negatively charged nanoparticles, no adsorption occurs. Our work highlights the importance of surface chemistry and adsorption on nanoparticle behavior in porous media and suggests that fundamental NMR behavior of media may be controlled with targeted adsorption of suitable nanoparticles.