bluuebunny/crossref_metadata_2025_split huggingface dataset:
Liquids Rich Organic Shale Recovery Factor Application
Authors: Barba Robert E. 
Published: September 2015

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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 &lt; 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.