bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling and Operation of Oil Removal and Desalting Oilfield Brines With Modular Units
Authors: Barrufet M. , Burnett D. , Mareth B. 
Published: December 2007

Abstract
Oilfield brine is the largest volume of waste generated by the oil and gas industry; typical produced brine volumes may easily exceed the oil production by 10 times with total dissolved solids ranging from 1,000 to over 250,000 ppm. Handling costs of produced brine may lead to the premature abandonment of many oil and gas wells. At the same time that oil and gas operators are trying to cope with excess produced water, many states are critically short of freshwater resources.
This paper describes and validates a process to treat this brine to meet the standards for irrigation-quality water. Components of the proposed brine-conversion plant include both microfiltration and a pretreatment system for the removal of solid particles and oil using sorption pellets made of a modified clay material, and reverse osmosis (RO) units with a variety of interchangeable semipermeable membranes for the removal of dissolved salts.
We collected experimental data for oil/water separation of controlled mixtures using packed columns with modified clay particles. The average oil loading capacity of these particles is better than activated carbon (over 60%) and our experimental results indicate that packed beds can remove over 90% of the oil.
We screened a variety of RO membranes and selected one to conduct a series of experiments with brines with salinity up to 40,000 ppm, transmembrane pressures up to 1,000 psia, and various rates. Our experiments indicate salt rejections of 95 to 99% depending upon the initial salt concentration, transmembrane pressure, and rate.
Based upon these experiments, we modeled and coupled these two processes. Our model can scale up a process to any desired throughput rate and concentration specifications. Simulation results indicate that at proper integration and configuration of oil adsorption and RO units, depending upon initial total dissolved solids (TDS), up to 90% of the brine may be recovered as fresh water.
Technology and Methods Used To Reduce Water Production in the Lower Delaware Sands of Southeastern New Mexico and West Texas
Authors: Shahan T. , Briney M. , Reyes R. , Creel P. , Dalrymple D. 
Published: December 2007

Abstract
Producing hydrocarbons from the lower Delaware formation in SE New Mexico and West Texas is often associated with high water production. In the Matthews Field in West Texas (Reeves County), an operator was encountering water production of over 600 BWPD (bbl of water per day) from wells that had been treated. The stimulation techniques and processes were modified in an attempt to improve the production results. Multiple stage treatments using coiled tubing (CT) with selective placement controls and reduced rates were performed to lower the fracture height growth. This method included using conventional fracturing fluids, specialized coiled tubing perforating and controlled fracturing placement, and a relative permeability modifier (RPM) capable of reducing the potential for water production by coating the formation rock. This paper will detail how these operations were performed.
Treatment of Produced Water with an Ultrafiltration (UF) Membrane—A Field Trial
Authors: Lee J. M. , Frankiewicz T. 
Published: December 2007

Abstract
A hydrophilic ultra-filtration membrane was pilot tested for its ability to clean oilfield produced water over a four month period at a West Texas location.The UF membrane has a pore size of 0.01 microns and was operated in a cross flow mode to maintain surface cleanliness.The pilot skid included desanding and deoiling hydrocyclones as pretreatment devices.Process variables investigated included the permeate flow to reject flow ratio, membrane cleaning frequency, and the effect of feed water quality on membrane performance.Based on this test, design criteria were determined and operating costs estimated for a full scale facility.
The pilot skid routinely discharged permeate water with total oil and grease &lt; 2 mg/liter.The effectiveness of pretreatment was essential to maintaining membrane permeability.During the test, the hydrocyclone's solid and oil removal efficiencies averaged 73% and 54% respectively.Emulsified oil droplets were found to be carrying 5-10 micron oil coated solids into the membrane unit.
Based upon this pilot test program, the operating cost for a full scale membrane unit, to produce 25,000 BPD of permeate water with &lt; 2 mg/liter residual oil, is estimated at 9.7 cents/bbl.Overall water recovery would exceed 98%.The successful implementation of this technology is dependent on the water quality fed to the membrane unit.The preferred specifications for the UF membrane feed water are &lt; 50 ppm oil and &lt; 15 ppm solids.
Mechanistic Basis for Hysteresis in Multiphase Transport Properties
Authors: Gladkikh M. N. , Bryant S. L. , Herrick D. C. 
Published: December 2007

Abstract
Macroscopic properties of porous media containing two immiscible fluids, such as capillary pressure, relative permeabilities, and resistivity index, are fundamental to petroleum engineering. In this work we present a methodology for obtaining a priori understanding of hysteresis in these macroscopic properties. The approach is based on the mechanistic modeling of fluid displacement processes at the grain scale in a random dense packing of equal spheres. The method allows computing pore-level fluid configurations, which, in turn, allows direct calculation of macroscopic properties. Meniscus motion at the grain scale is entirely mechanistic, so any hysteresis that emerges does so exclusively from the interaction between the mechanics and the grain space geometry. Our model predicts that hysteresis during the fluid displacement cycle (drainage then imbibition of the wetting phase) has a significant effect on relative permeability and resistivity index. In particular, the usual assumption that the electrical parameter n in Archie's equation, determined by a drainage experiment, is equally applicable to imbibition is unwarranted. The results for electrical properties are also presented as electrical efficiency, which was developed specifically to account for the effects of pore-level geometry.
The predictions made in this work are compared with existing experimental data and found consistent with them. The methodology allows quantifying the influence of hysteresis in other conditions (consolidated rocks, varying wettability).
Sand-Arch Strength Under Fluid Flow with and without Capillary Pressure
Authors: Arii H. , Morita N. , Ito Y. , Takano E. 
Published: December 2007

Abstract
There are more than 15 sand control methods and one of the frequently used methods is the rate control method. There are mainly two cases where the rate control method can be applied: (1) permeability is significantly damaged around a well and the sand problem induced by erosion failure due to abnormally large drawdown can be controlled by the rate control method, and (2) the stability of a sand-arch built by disintegrated sand particles can be controlled by rate control. A series of laboratory tests were conducted in this work to measure the sand-arch strength using a polyaxial confining cell. The parameters changed in these experiments were the ratio of grain size to cavity diameter, grain distribution, cavity diameter, oil-water ratio, confining stress and directional stress. A similar experiment was previously conducted by the Colorado School of Minesand IKU, however, the tests conducted by the Colorado School of Mines used 20-40 mesh loose sands which are too coarse compared with actual reservoir sands, and IKU used air instead of liquid flow. Both of them used some immobile water saturation while the saturation change from 0 to 30% significantly reveals the complex phenomena of water effects upon sand-arch strength. The main objective of the laboratory tests was to separate the mechanical arch strength and the strength induced by the capillary pressure. It used a large grain size to observe large mechanical arch strength without capillary pressure effects andan intermediate grain size to observe capillary pressure effects. An analytical solution of a spherical cavity growth due to erosion of the post-failure zone is also developed to verify the observed phenomena in the laboratory tests.
Integration of Fracture Data into 3D Geomechanical Modeling To Enhance Fractured Reservoirs Characterization
Authors: Macé L. , Muron P. , Mallet J.-L. 
Published: December 2007

Abstract
Natural fractures have a dramatic impact on reservoirs in terms of oil recovery because they often control the hydraulic flow as conductors (open fractures) or barriers (sealed fractures). However, fracture parameters are poorly constrained by reservoir data, due to the low seismic resolution and to the clustering of 1D data along wells.
To enhance flow prediction, we suggest improving the characterization of Naturally Fractured Reservoirs by integrating well data with the history of stresses obtained by three-dimensional structural restoration (3D balanced unfolding). When unfolding a layer, boundary conditions are applied to mesh displacements to unfold the upper horizon and remove the latest brittle and ductile deformation increment. A linear isotropic elastic model governs restoration behavior, accounting for mechanical contrasts in the reservoir. Three-dimensional strains and stresses are derived from these displacements. Orientation of theoretical tectonic fractures is then geomechanically deduced from the principal strain directions.
Moreover, the orientations of fractures observed at wells (cores or image logs) provide implicit information on the principal directions of paleo-stress. Considering a given failure criterion, the observed fracture orientation is used to constrain the relative directions of paleo-stress components. Through this original approach, the 3D deformation is calibrated by observed geological data.
Therefore, the hybrid geometrical and geomechanical restoration that has been developed accounts for reservoir heterogeneities and is globally constrained by paleo-stresses deduced from fractures observed along wells.
This methodology is applied to a real reservoir located in North America and the strains predicted are used to generate 3D Discrete Fracture Networks. The key benefit of this approach, as compared to conventional methods, is to enhance fracture characterization by directly integrating observed fracture data into the geomechanical process.
Prediction of Well Performance Instability in Thin Layered Reservoirs
Authors: Belfroid S. P. C. , Sturm W. L. , Alberts G. J. N. , Peters M. C. A. M. , Schiferli W. 
Published: December 2007

Abstract
By using a full dynamic model for both the well and the near well reservoir, a large range of instabilities can be simulated. These instabilities include gas lift heading, severes slugging and compressibility effects. To simulate these types of fluctuations it is necessary to use an integrated dynamic model for the complete system. Using a constant productivity index to describe the inflow or using lift curves for the well are not sufficient to capture the dynamics. In this paper a well is described where reservoir-well interaction leads to unstable well behaviour. In order to investigate the cause for the unstable production a full dynamic model was developed for both the well and the near well reservoir. The simulation results are compared to field data of this well. The instabilities encountered at this well were explained by a combination of severe slugging in the well and the influence of the dynamics of the reservoir. The wellbore could act as a gas storage volume in which a pressure build up can take place. The well model used was a three phase dynamic models based of the drift flux formulation. For the reservoir basic single phase oil model was used to simulate a radial inflow. In the reservoir the compressibility of the oil is taken into account.
4D Monitoring of an Underground Gas Storage Case Using an Integrated History Matching Technique
Authors: Langlais V. , Mezghani M. , Lucet N. , Huguet F. 
Published: December 2007

Abstract
As time lapse seismic data are frequently available to guide the understanding of fluid flow behavior, a methodology has been developed to produce a fine scale geological model constrained by time dependent data, wells and 4D in a quantitative way. This enables us to keep the coarse model used in fluid flow simulations consistent with the fine scale geological model [1]. The objectives of this work are to validate the proposed methodology on a realistic synthetic case and to assess the impact of 4D in prediction improvements. Are we doing a better job by using 4D in history matching?
A synthetic reference case was derived from a Gaz de France gas storage site where gas injection and production are alternated over a 20-year period. Seven geological units showing various degrees of heterogeneities describe this full field dynamic model. A fine scale reference geological model was built (9.7 million cells), then upscaled and used in flow simulator. This model honored the observed static and dynamic well data (17 wells). Saturation maps from fluid flow simulation and a petro elastic model (PEM) were used to derive acoustic and elastic parameters. This reference data set will provide a point of comparison to assess and quantify the prediction performances as the time period is divided into history and prediction.
A workflow was developed to build a consistent fine scale geological model, a fluid flow model and seismic data using a PEM and accounting for the various scales. The forward modeling part of the workflow was used to compute simulated well data, impedances Ip, Is and time shift data. Then using an optimization loop, the models were constrained to observed well data and time lapse seismic data. The case study validates the methodology and shows an efficient way to include quantitatively 4D information while keeping consistency through the modeling chain. The model constrained by well data and 4D seismic data lead to more accurate predictions than the model constrained by well data only.
Bean-up Guidelines for Sand-Control Completions
Authors: Geilikman M. B. , Dria D. E. , Stewart D. R. , Wong G. K. 
Published: December 2007

Abstract
This paper presents a model that quantifies the production impairment caused by fines mobilization and induced by the transient gradient of pressure from the bean-up operations. Laboratory flow tests using field core samples and synthetic cores composed of different mixtures of sand and fines materials, all stressed under representative in-situ stress conditions were performed. They systematically assessed mechanisms of fines mobilization and amounts of permeability impairment as functions of different sizes of fines, amounts of fines, and flow velocities. Results of flow tests and transient gradient pressures generated by bean-up operations were combined to determine the additional production impairment or skin induced by flow velocity for the well. Application of this model allows engineers to calculate the well skin as a function of drawdown, total time of bean-up, time between choke changes, and number of steps or choke changes in the bean-up operations.
Application of this method provided some general qualitative bean-up recommendations (based on production impairment caused by fines mobilization): Bean-up with smaller incremental drawdown and shorter time between choke changes is preferred to bean-up with a higher drawdown but with a longer waiting time between choke changesContinuous bean-up is better than step-wise bean-upSkin inflicted by bean-up is more sensitive to a higher drawdown than to a shorter total bean-up time.Bean-ups with the same drawdown can be performed faster for reservoirs with higher diffusivity constant
The applied field example of a cased hole gravel pack well showed the bean-up inflicted skin ranged between 1 and 3 units. The effect of eliminating the transient gradient of pressure entirely only resulted in a reduction of 1 skin unit. Therefore, at least for this case, the impact of bean-up on production impairment based on fines mobilization was low. Other factors such as flow assurance; rock failures and sand production (and their impacts on sand control completion impairment and reliability) in the near well bore area may be more critical for optimizing the bean-up operations. Further studies in these areas are encouraged. Consideration of fines impairment for bean-up of sand control well is still warranted for formation sand with large amounts of "bad" fines and under low in-situ effective stress conditions.
This paper should be of interest to both the completion and production engineering communities.
The Key to Successfully Applying Today's Lost Circulation Solutions
Authors: Wang H. , Sweatman R. , Engelman B. , Deeg W. , Whitfill D. 
Published: December 2007

Abstract
Though strengthening boreholes with particulate treated mud has achieved tremendous success in the past year, the theory behind the process still has not been widely accepted. Rock mechanics analysis and laboratory data review are performed in this paper to illustrate deepened understanding on some key points that are controversial. Algorithms have been developed and demonstrated for obtaining critical parameters in designing such jobs for improving hoop stress, by which a wellbore can be strengthened while drilling.
Discussion of mechanisms and case histories has led to the development of systems that are designed to improve wellbore-pressure containment (WPC) by improving least principal stress. These systems are designed to function independent of formation permeability, unlike high fluid-loss and high solid-content squeeze pills. This method is normally applied when long fractures exist and when lost circulation has occurred.
Since the first approach is proactive and the latter remedial or corrective, combining the two approaches can create synergy for borehole strengthening.
A computer-aided design (CAD) process is also demonstrated for better use of available information in designing a deformable, viscous, and cohesive (DVC) system.
Semianalytical Stream-Function Solutions on Unstructured Grids for Flow in Heterogeneous Media
Authors: Hazlett R. D. , Babu D. K. , Lake L. W. 
Published: December 2007

Abstract
This paper outlines a Boundary Element Method (BEM) for a piece-wise analytic solution of the Laplace (Poisson) equation for pseudo-steady state, single phase flow on unstructured, rectangular grids.The method models flow through a reservoir that has been segmented into interacting homogeneous rectangular regions; no further discretization of the solution space analogous to grid refinement in numerical schemes is required for improved accuracy.Previous work on pressure distribution modeling is extended to analytically capture the stream-function.Stream-function solutions can then form the basis for other performance measures, such as improved oil recovery efficiency estimation or tracer flow analysis.Moving beyond structured grids into unstructured grid geometry allows for advanced flexibility in problem development and improved efficiency in solution construction.The analytic approach avoids the need for numerical differentiation of the pressure field and particle tracking methods to recover streamlines.Capturing flow around thin impermeable barriers, without local grid refinement, is demonstrated to showcase the robustness of the technique in handling complex reservoir architecture.
Implementation and Application of a Hybrid Multipoint Flux Approximation for Reservoir Simulation on Corner-Point Grids
Authors: Juanes R. , Kim J. , Matringe S. F. , Thomas L. K. 
Published: December 2007

Abstract
Accurate and robust discretization of the fluid flow equations is required to account for the extreme heterogeneity of oil and gas reservoirs, and the combined effect of anisotropy and grid distortion, necessary to adapt the grid to the geology. There is a growing need for handling distorted unstructured grids and full permeability tensors that appear after upscaling of the fine-scale permeability field. The classical cell-centered finite difference method results in a 7-point stencil and is insufficient to account for these effects. A number of closely related methods, coined as multipoint flux approximations (MPFA), have been proposed recently and are currently under active development. The basic principle of MPFA is that the flux across an interface between two gridblocks depends on the state variables (pressure and saturations) of more than two gridblocks. MPFA leads naturally to an enhanced finite volume method with a 27-point stencil.
In this paper, we implement a variant of the MPFA method for corner-point geometry hexahedral grids. Motivated by the very high aspect ratio of gridblocks in typical reservoir models (ratios as high as 100:1 are not uncommon), we propose a hybrid method that employs a multipoint flux approximation in the areal direction and a two-point flux approximation in the vertical direction. This restricted MPFA method leads to an 11-point stencil, therefore reducing the computational effort significantly. We discuss the implementation of the method in detail. We evaluate its performance on a number of test cases and show that, for typical applications, this simplification does not greatly compromise the accuracy of the solution.
What is the Characteristic Length Scale for Permeability? Direct Analysis From Microtomographic Data
Authors: Bauget F. , Arns C. H. , Saadatfar M. , Sheppard A. P. , Sok R. M. , Turner M. L. , Pinczewski W. V. , Knackstedt M. A. 
Published: December 2007

Abstract
Rock formation permeability is arguably the most important flow parameter associated with subsurface production and injection. Its importance is reflected by the number of techniques (well-log evaluation and correlation, core measurement and well testing) used to estimate it. Clearly permeability should be linked to other porous media properties (e.g., surface area, porosity, pore/grain size). There have been numerous attempts over the last sixty years to establish a relationship between the permeability of a rock and other characteristic rock properties. Most empirical approaches for the prediction of permeability, which has units of length squared, propose a function of a characteristic length scale, formation factor (tortuosity) and porosity. The most widely used is the Carmen-Kozeny equation where the length scale is equated to the hydraulic radius (pore volume / pore surface area). Other length scales used include a critical pore radius associated with mercury injection experiments (Katz-Thompson), lengths associated with NMR relaxation (e.g., T2) and grain size and rock fabric measures.
To uncover the relationship between permeability and other pore scale properties requires directly measuring the geometric and transport properties of the pore system. This is now possible with 3D microtomographic imaging (Knackstedt et.al. SPE 87009, Arns et.al. SPE 90368). In this paper we describe a comprehensive study of permeability correlation across a range of rock types. We directly compute permeability, formation factor, NMR response, hydraulic radius, rock fabric and texture, pore size and capillary pressure on 3D microtomographic images of 39 porous materials including over 30 clastic and carbonate samples from a wide range of reservoirs. Subsampling enables one to generate more than 6500 "independent" samples. Empirical correlations between permeability and various length scales are tested for a range of lithotypes including unconsolidated sands, homogeneous sands, consolidated reservoir sands, limestones and reservoir carbonates. We find that the most robust length scale correlation is based on the critical pore radius. All correlations which use the Formation factor as a measure of tortuosity give good predictions. Empirical correlations for permeability based on grain size perform well for permeabilities greater than one Darcy.