bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Upscaling Method of Relative Permeability Curves for Reservoir Simulation
Authors: Wang Kefei , Killough John E. , Sepehrnoori Kamy 
Published: October 2009

Abstract
Relative permeability is one of the most important factors in numerical reservoir simulation. Although the relative permeability curves may be available on a very fine level of detail, their direct use to estimate the amount of uncertainty, which requires thousands of reservoir simulation runs, is generally not practical because of the excessive computer time and memory that would be required. Despite the extensive research that has been performed in the past few decades, effective upscaling to reduce computation times in highly heterogeneous reservoir still remains a challenging procedure.
In this paper, we demonstrate how conventional upscaling approaches may lead to large errors. To overcome the inaccuracy, we investigated and developed a new relative permeability upscaling technique for the coarse scale modeling for heterogeneous reservoirs. In our new method, single-phase upscaling was applied at the beginning to set up the base case for optimization. The regression runs were conducted by non-linear optimization. The decision variables in a standard Corey and logistic form were used to check the errors between the coarse and fine models. After the procedure converged, a new relative permeability curve for the coarse model was generated. The match for the breakthrough time and post-breakthrough performance was very accurate using the new relative permeability curves. Predictability with the new curves also appeared to be substantially improved; the newly generated relative permeability curves can be used over periods beyond that of the original match.
The new method was verified by using three-phase, 3D, and highly heterogeneous reservoir models. These verifications were performed on large models approaching one million cells with black oil and composition fluids with waterflooding and water-alternating-gas (WAG) recovery processes.
The ultimate goal of the work has been to use the upscaled models with modified relative permeabilities to investigate how uncertainty is affected by upscaling. The fine scale results indicate that more reasonable results can be obtained for estimating the effect of uncertainty with the new upscaling technique as compared to conventional methods, with computation time orders of magnitude faster than previously available.
Determination of Concentration Dependent Diffusivity Coefficient in Solvent Gas Heavy Oil System
Authors: Etminan S. R. , Maini B. B. , Hassanzadeh H. , Chen Zh. 
Published: October 2009

Abstract
Molecular diffusion coefficient is an important parameter in modeling mass-transfer based reservoir processes. However, experimentally measured diffusivities for heavy oil systems are relatively scarce and no standardized method exists for measurements of this important parameter. The available measurement techniques are tedious, expensive and often not very reliable. There is an obvious need for developing improved methods for measuring diffusivity of gases in heavy oils.
It is well known that as a gas dissolves into heavy oil, the oil viscosity drops considerably and this affects the diffusivity. The objective of this work is to measure the diffusivity of highly soluble gaseous solvents in heavy oils at different concentration levels. We have developed a modified pressure decay method that maintains constant concentration at the gas-liquid interface and measures the amount of gas transferred to the liquid as a function of time. An analytical solution has been developed for finding diffusion coefficient and the equilibrium solubility of gas in the oil at the test pressure. To study the concentration dependence of diffusivity, a stepwise increase in pressure is used starting from a low pressure. Through this stepwise procedure, a diffusion coefficient is measured for each gas saturation pressure (concentration), going from low pressure to near gas dew point pressure in 5 to 6 steps. The bitumen height in our cell is updated at each pressure to account for bitumen swelling. Propane was used as vapor solvents and diffusion cell was kept at constant temperature.
Calibration of High-Resolution Reservoir Models Using Transient Pressure Data
Authors: Kim Jong Uk , Datta-Gupta Akhil , Brouwer Roald , Haynes Byron 
Published: October 2009

Abstract
Integrating dynamic data into high resolution reservoir models is a crucial aspect of any optimal reservoir development and management strategy. In this regard, pressure data provides several advantages. First, pressure transient tests are easier and less expensive to carry out in the field. Second, pressure responses can be obtained early in the field life compared to watercut or tracer data. Finally, the pressure perturbations travel much faster compared to tracer or water front, resulting in quicker response in the field. This makes interference tests much more appealing compared to tracer tests which may require months to see a field response. However, the computation cost and localized nature of pressure sensitivities pose difficulties in history matching transient pressure data with a finite difference model. Also, pressure tests from multiple wells are difficult to analyze because of superposition of pressure responses.
We propose a fast and robust approach to integrating transient pressure data using a trajectory-based approach that relies on a high frequency asymptotic solution of the diffusivity equation. The trajectory or ray-based methods are routinely used in seismic tomography. In this paper, we make a detailed comparison of streamlines and seismic rays and examine the applicability of streamline-based methods for transient pressure data inversion. Specifically, the high frequency asymptotic approach allows us to analytically compute the sensitivity of the pressure data with respect to reservoir properties such as porosity and permeability. This results in a very efficient approach for the integration of pressure data into geologic models.
We apply our proposed method to transient pressure data from both single well test and multi-well interference tests. Our results demonstrate the advantage of performing interference tests compared to performing tracer tests in terms of identifying heterogeneities early in the field life. Finally, we apply this approach to data from a multiwell interference test in a Middle Eastern reservoir. Specifically, the pressure data obtained from permanent downhole gauges (PDG) in multiple wells are utilized to determine communications in the reservoir and to derive quantitative information about the permeability distribution in the reservoir for potential aid in the design and optimization of a miscible gas flood.
A Practical Method for Minimum Miscibility Pressure Estimation of Contaminated Gas Mixtures
Authors: Johns R. T. , Ahmadi Kaveh , Zhou D. , Yan M. 
Published: October 2009

AbstractMinimum miscibility pressure (MMP) is a key parameter in the design of gas floods. Injection gas compositions often vary during the life of a gas flood owing to reinjection and mixing of fluids in situ. Understanding the impact of the gas compositional changes on the MMP is essential to optimal design of field-wide pressure management and CO2 utilization. Determining the MMP by slim tube or other methods for each possible gas mixture is impractical. This paper gives an easy and accurate way to determine MMPs for any multicomponent gas based solely on a few estimates of MMPs from binary gas mixtures.We use the method of characteristics (MOC) and our newly developed mixing-cell method to estimate MMPs for binary gases, where the primary component is contaminated by another component. We demonstrate how to calculate MMPs for multicomponent solvents using two example reservoir oils displaced by CO2 contaminated by various mixtures of N2, CH4, C2, C3, and H2S. We also examine the sensitivity of local displacement efficiency to dispersion for binary gas mixtures using one-dimensional simulation.The results show that the MMP for gases composed of two or more components can be very accurately estimated from a linear mole-fraction weighted function of the MMPs determined from each binary gas mixture, such as CO2–CH4 and CO2–C2. For a West Texas crude, the MMPs for contaminated CO2 injection streams are determined accurately over a wide range using only the pure-component MMPs. The accuracy of the MMPs are within +/− 15 psia of those calculated using mixing cell and slim-tube simulations. That is, the MMP for all possible gas compositions is nearly a linear combination of the pure-component MMPs. For the second oil displacement by impure CO2, however, the linear interpolation is accurate as long as the contaminant levels are less than about 20% by mole fraction. For this volatile oil we use an extrapolation of the MMPs for small contaminant concentrations in our linear MMP estimation function.
Compositional Modeling in Three-Phase Flow for CO2 and Other Fluid Injections Using Higher-Order Finite Element Methods
Authors: Sun Shuyu , Firoozabadi Abbas 
Published: October 2009

Abstract
CO2 injection is one of the most attractive options for water-flooded reservoirs. The numerical simulation of the process is computationally challenging; it requires accurate compositional modeling of three-phase flow in porous media. In this work, we simulate for the first time, three-phase compositional flow using higher-order finite element methods. Our numerical model is based on an iterative IMPEC coupling of the pressure equation and species transport equations, which are solved by mixed finite element (MFE) and discontinuous Galerkin (DG) methods, respectively. A number of numerical examples in one and two dimensions are presented to illustrate the modeling capability of the proposed algorithm. We take into account various phase behavior effects including swelling, viscosity reduction and vaporization from CO2 injection in water-flooded reservoirs. The model captures the spike in concentration. Numerical comparison of our combined MFE-DG approach with the conventional upstream weighted finite difference method indicates that MFE-DG has low numerical diffusion. The proposed MFE-DG method can capture the solution discontinuities and yield accurate prediction of shock locations arising in computational three-phase flow. The work sets the stage for broad extension of the higher-order methods for numerical simulation of three-phase flow for complex geometries and complex processes.
Managing Your Business Using Integrated PRMS and SEC Standards
Authors: Etherington John R. 
Published: October 2009

Abstract
The SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS) published in March 2007 provides an international industry standard for classifying and reporting reserves and resources. Many companies have adopted PRMS directly, or in modified versions, as part of their internal asset management systems. However, publicly traded companies have historically been forced to maintain two sets of reserves and resources records: one for internal project and portfolio management, and one for regulatory disclosures. This may no longer be required for those issuers listed on U.S. stock exchanges. On December 29, 2008, the U.S. Securities and Exchange Commission (SEC) published revised rules for disclosure of oil and gas reserves that closely align with the evaluation principles and reserves guidelines contained in PRMS.
The SEC mandates reporting of Proved Reserves while disclosure of Probable and Possible Reserves is now optional. These disclosures may be viewed as a subset of PRMS which also includes guidance on Contingent and Prospective Resources. While PRMS reserves are confined to projects that are economic based on internal price forecasts, the SEC requires use of 12-month historical average prices. However, the systems may be integrated with options to include supplemental assessments based on alternative pricing scenarios. Both PRMS and SEC accommodate deterministic and probabilistic estimates of "as sold" hydrocarbon products irrespective of the extraction method and interim processing required.
This alignment allows the same resource evaluation to underpin both internal business processes (project tracking, portfolio management) and regulatory disclosures including reconciliations by category. It is now feasible to design a single database to support reporting requirements for both functions at multiple aggregation levels based on geographic area, product type, resource class, and resource category.
Companies can now manage their business based on PRMS industry standards but accommodate SEC disclosures within a single integrated assessment system. In addition to allowing significant process efficiencies, a common system improves the linkage between technical and business analyses providing a clear audit trail.
Development and Application of Upscaling Techniques for Modeling Near-Well Flow in Heterogeneous Reservoirs
Authors: Chen Yuguang , Bernath Alan , Rai Himansu , Muron Pierre 
Published: October 2009

Abstract
Upscaling is often applied in reservoir simulation to coarsen highly detailed geological descriptions. Flow in petroleum reservoirs is mainly driven by wells, thus upscaling of near-well flow is important in coarse-scale flow simulation. In this paper, we present an upscaling methodology, which involves a recently developed coarse-scale well model, combined with transmissibility upscaling for inter-well regions. The coarse-scale well model, referred to as near-well arithmetic averaging, directly uses fine-scale permeabilities along well trajectories to compute coarse-scale well index. Compared to flow-based near-well upscaling techniques, this method does not require solving any fine-scale flow problem, but can approximately capture the effects of fine-scale heterogeneity in near-well regions. Therefore it is straightforward for use and does not incur any computational overhead. This model is implemented in a general reservoir modeling framework, which allows for the handling of realistic grid geometry and well completion from real field data. In inter-well regions, we apply transmissibility upscaling, which directly computes the upscaled transmissibility (defined at block interfaces) rather than permeability upscaling. Standard upscaling methods (local permeability and border region permeability upscaling) are also considered to illustrate their potential errors when not being applied appropriately (e.g., without near-well treatment). We apply the proposed upscaling methodology (near-well arithmetic averaging for near-well flow and transmissibility upscaling for inter-well regions) to sector models from real field cases. All the cases involve general multiphase flow simulations, including primary production, water flooding to oil-water and three-phase flow models. It is shown that the proposed methodology consistently improves the accuracy of standard upscaling methods that are commonly used in the industry and for some cases, provides accurate flow predictions, demonstrating its practical applicability for real field cases.
An Improved Model for Water-Hydrocarbon Surface Tension at Reservoir Conditions
Authors: Sutton Robert P. 
Published: October 2009

Abstract
The surface tension that exists between hydrocarbon and water systems is an important property within the petroleum industry. Uses of this property range from quantifying its effects on capillary pressure which governs the vertical saturation distribution of hydrocarbons in a reservoir to determining liquid droplet size for multiphase flow calculations. A general correlation for estimating water-hydrocarbon surface tension has been developed. Prior generalized methods presented in the literature were found to be in error for gases other than methane and did not adequately characterize the change in surface tension with temperature. A large database consisting of 1902 data points was created as part of the development of the correlation. Pure hydrocarbon component surface tension measurements against pure water provide the basis for this database. Data ranging from methane through hexadecane as well as benzene and toluene were included in the main database. Pure water data at vapor pressure equilibrium was also included in the analysis to ensure that changes in surface tension with temperature were modeled accurately. In addition, natural gas, natural gas-carbon dioxide and natural gas-nitrogen mixtures with pure water were tested with the new correlation to ensure realistic scenarios could be accurately modeled. Pressure data covered the range from 14.7 to 43,526 psia while temperature ranged 33–500 °F which ensures that both conventional and HPHT conditions can be modeled. Real hydrocarbon-water systems usually contain dissolved salts in the water; therefore, a salinity correction must be applied to account for the increase in surface tension. Available data from the literature was examined and a suitable correction is proposed. This paper presents the analysis of an exhaustive database and proposes a new correlation to model water-hydrocarbon surface tension with significantly higher accuracy.
Laboratory Testing of Downhole Gas Separators in Inclined Wellbore Configurations
Authors: Alabi O. , Podio A. L. 
Published: October 2009

Abstract
This paper attempts to establish the effects, if any, of wellbore inclination on the performance of downhole gas separators. Different downhole gas separator designs have been extensively studied in the laboratory and far reaching conclusions have been drawn from observations made in the laboratory for vertical wellbores. However, it is pertinent to note that most wellbores are not truly vertical and a survey which shows the deviation of the wellbore from a vertical reference point is often present in most wellbore configurations. Hence, this paper compares the performance of different downhole gas separator designs in a vertical wellbore set up with that of the same downhole gas separators operating under similar conditions but installed in an inclined wellbore set up.
Technology has made it possible to drill horizontal wells which are fast becoming ubiquitous in most oilfields. With gravity forces dominating separation in static downhole gas separators; it is certainly logical to study the effect of wellbore inclination on the separation efficiency of downhole gas separators as transport properties of multi-phase fluids are affected by gravity. With the above mentioned arguments, it becomes imperative to study downhole gas separators under conditions which best simulate oilfield operations.
The approach utilizes an instrumented full scale model of an inclined well-bore and separator constructed with clear acrylic pipe. The base case consists of the entire wellbore and separator set up installed vertically and subsequent experiments were performed with the wellbore inclination angle at 45°. An air and water mixture is injected through the well's perforations. The air and water flow rate measurements define a performance plot of each separator design with respect to wellbore inclination. Continuous flow conditions were applied in all tests
Results obtained from laboratory annular bubble rise experiments show that in an inclined set up, the bubbles tend to move along the walls of tubing where the effect of drag is maximum. Results from the annular bubble rise experiments in an inclined wellbore equally show that the upwards motion of the smaller bubbles tend to be considerably reduced and sometimes halted by drag while on the contrary, the larger bubble (Taylor type bubbles) have higher mobility along the walls of the tubing.
Also, results from the downhole gas separator performance tests conducted in a wellbore inclined at 45° indicate that at similar operating conditions, a gravity driven downhole gas separator installed in a wellbore inclined at 45° would perform better than the same gravity driven downhole gas separator in a vertical wellbore. While at similar operating conditions, a centrifugal force driven downhole gas separator installed in a vertical wellbore would perform better than the same centrifugal force driven downhole gas separator in a wellbore inclined at 45°.
Field Test Results of an Electromechanical Precision Pipe-Cutting Tool
Authors: Fanini O. N. , Fuhst K. , Cousin D. , Moeller M. , Ahmed M. A. , Ross B. , Krueger S. , Lowson P. , Cattanach S. M. 
Published: October 2009

Abstract
A recently developed electromechanical precision pipe-cutting tool is being field tested. Its primary applications are to cut and free stuck pipe (tubing or drillpipe) or cut pipe to modify a production completion installation. Cutting pipe in today's complex completions presents many challenges. Testing of this new cutting technology has demonstrated significant advantages over previously used equipment. It is non-ballistic, has a large cutting range for a wide range of metal pipes, provides cut monitoring and success detection. The precision of the cut is facilitated by the tool's internal programming (smart function) which allows for specifying the type of metal to be cut, monitoring the depth of the cut, recognizing the drag and making the appropriate adjustments to complete a cut. The ability to complete multiple precise cuts reduces associated rig time. Its large operating temperature and pressure ratings (20,000 psi), large cutting size range, and portability make possible quick deployment to offshore and land operations. Additional field-demonstrated capabilities include: performs accurate smooth cuts, cuts harder metals with a high chrome content, performs precision cuts for inner pipe cutting, works at any deviation, produces minimum debris, surface system allows application to any wireline, does not require circulation holes for the cutting device, operation deployment is not constrained by chemical issues relate to safety and environment, the cutter's light weight, short shipping length (two sections, each less than 10 feet in length), and compatible portable support equipment allow for quick deployment in a variety of transport modes. This paper includes a case study to illustrate the operating challenges associated with tubing and drillpipe cutting in a variety of conditions and environments.
Practical Solutions for Pressure Transient Responses of Fractured Horizontal Wells in Unconventional Reservoirs
Authors: Brown M. , Ozkan E. , Raghavan R. , Kazemi H. 
Published: October 2009

Abstract
This paper presents an analytical trilinear flow solution to simulate the pressure transient and production behavior of fractured horizontal wells in unconventional reservoirs (Ozkan et al., 2009). The model is simple, but versatile enough to incorporate the fundamental petrophysical characteristics of unconventional reservoirs, including the intrinsic properties of the matrix and the natural fractures. Special characteristics of fluid exchange among various reservoir components may also be considered. This practical solution provides an excellent alternative to rigorous solutions, which are cumbersome to evaluate. One of the advantages of the trilinear flow solution is its convenience in deriving asymptotic approximations. Though linear and bilinear flow regimes have been noted for fractured horizontal wells in the literature based on their diagnostic features, they have not been associated with particular reservoir characteristics and flow relationships. The solutions documented in this work provide insight about potential flow regimes and the conditions leading to these flow regimes. Identification of these flow regimes is important for the characterization of unconventional reservoirs from pressure transient tests. Because of its relative simplicity, the trilinear flow solution does not require special expertise to compute and apply.