bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Resume of the Drilling Fluids Used on the World's Deepest Well
Authors: McFarland Wayne , Meyer Robert 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Introduction
Lone Star Producing Company, Dallas, has set a new depth record, 31,441 feet, on their Bertha Rogers #1, near Burns Flat, Oklahoma. The old record, also held by Lone Star, is 30,050 feet, set on their #1 E. D. Baden in the same general area of Oklahoma.
Since these wells are the first ever to exceed 30,000 feet, they are the trend setters as the industry is forced to probe deeper for hydrocarbon deposits and/or geothermal energy. The knowledge and experience gained on these wells should prove invaluable in the planning of future deep tests.
This paper deals with one facit of the latest well, the drilling fluids. Included is a brief description of the geological characteristics that were expected in this well, a summary of the mud types and problems encountered while drilling, and some discussion of the auxiliary equipment and testing programs that are necessary for maintaining an optimum fluid at all times. It is hoped that from all this, the reader will gain some insight into the details concerned in handling a job of this magnitude, and possibly use this information as an aid possibly use this information as an aid for improvement in the future.

EXPECTED GEOLOGY
As is the case for most wells, the expected geological characteristics for the Rogers were determined from seismic data and offset well information in the same general area. Because of the depth, however, the bottom portion of the well could be classified as a rank wildcat, with the characteristics highly speculative.
The Burns Flat area of Oklahoma overlies part of the Southern flank of the Anadarko Basin. This flank is a steep, block faulted limb, paralleling the Amarillo-Wichita uplift (Fig. 1). The "Anticipated Geological Section" (Fig. 2) gives a better idea of the formations to be penetrated.
The primary target for this well was the Devonian dolomite (Hunton), which was non-commercial in the Baden test.
The sediments of the Anadarko basin are mainly carbonates with mixed layers of sand and shale. However, because of the intense folding, faulting, and uplifting that has taken place along the southern flank of this basin, massive sections of shale and some sand are predominant from about 12,500 feet to in predominant from about 12,500 feet to in excess of 23,000 feet.
A Parallel Multiblock/Multidomain Approach for Reservoir Simulation
Authors: Wheeler Mary F. , Arbogast Todd , Bryant Steven , Eaton Joe , Lu Qin , Peszynska Malgorzata , Yotov Ivan 
Published: December 2007

Abstract
Our approach for parallel multiphysics and multiscale simulation uses two levels of domain decomposition: physical and computational. First, the physical domain is decomposed into subdomains or blocks according to the geometry, geology, and physics/chemistry/biology. Each subdomain represents a single physical system, on a reasonable range of scales, such as a black oil region, a compositional region, a region to one side of a fault, or a near-wellbore region. Second, the computations are decomposed on a parallel machine for efficiency. That is, we use a multiblock or macro-hybrid approach, in which we describe a domain as a union of regions or blocks, and employ an appropriate hierarchical model on each block.
This approach allows one to define grids and computations independently on each block. This local grid structure has many advantages. It allows the most efficient and accurate discretization techniques to be employed in each block. The multiblock structure of the algebraic systems allows for the design and use of efficient domain decomposition solvers and preconditioners. Decomposition into independent blocks offers great flexibility in accommodating the shape of the external boundary, the presence of internal features such as faults and wells, and the need to refine a region of the domain in space or time (by treating it as a distinct block); interfacing structured and unstructured grids; and accommodating various models of multiscale and multiphysical phenomena. The resulting grid is not suited to direct application of discretization methods. We use mortar space techniques to impose physically meaningful, mass conservative, fluxmatching conditions on the interfaces between blocks.
We present numerical simulations to illustrate several of these decomposition strategies, including the coupling of IMPES and fully implicit models and upscaling by varying the number of degrees of freedom on the block interfaces.
Applications of a Parallel Simulator to Industrial Test Cases
Authors: Verdière Sophie , Quettier Lisette , Samier Pierre , Thompson Alan 
Published: December 2007

Abstract
Computer models of oil reservoirs are becoming more and more complex in order to represent the heterogeneity of rock structures more realistically. It is, however, necessary to restrict the resolution of models and the number of components in compositional models because of the limits of computer CPU time and memory. This leads to uncertainties in the simulation due to the averaging techniques used in petrophysics and in the modelling of surface processes.
Parallel computing is now an attractive solution to overcome these drawbacks by using the best of the hardware and software technology.
In this paper, we look at the efficiency of the parallel versions of Eclipse 100 and 300. We evaluate their speed, memory requirements and scalability using black oil and compositional models with up to 16 components on an SGI Origin 2000 with 16 processors. These are based on real fields and range from 100 000 to 4 500 000 cells with cells as small as 20×20×0.5 meters.
We examine the problems of deciding on the decomposition of domains, and the choice of message passing systems. We also discuss the optimal way of managing the job scheduling. We show the difficulties of pre and post processing large data sets and visualizing the results of simulations. The analysis of results of these test cases allowed us to quantify the benefits of a finer geological and fluid description. With the parallel option, we can now envisage the possibility of running weekend jobs overnight and overnight jobs during normal working hours.
We show that the jump of parallel computing from research to industrial applications provides real benefits to engineers.
A Mixed-Wet Hysteretic Relative Permeability and Capillary Pressure Model in a Chemical Compositional Reservoir Simulator
Authors: Delshad M. , Lenhard R. J. , Oostrom Mart , Pope G. A. , Yang S. 
Published: December 2007

Abstract
A crucial component of all multiphase flow models is the relationships among relative permeabilities, fluid saturations, and capillary pressures. Relative permeability and capillary pressure parametric models can be very useful for predicting fluid behavior in porous media. However, relative permeabilities and capillary pressures used in oil reservoir simulators are commonly determined via interpolation between laboratory measurements. A problem with this approach is that the relations are valid only for the specific saturation path measured. Therefore, simulations of oil production using different saturation paths than those measured are likely to be in error and can limit the investigation of alternative production scenarios. In this paper, saturation-history-dependent relative permeability and capillary pressure functions for mixed-wet rocks are discussed. Relative permeabilities are predicted via integrating a pore-distribution model between limits that reflect how oil and water are distributed in mixed-wet porous media. The proposed model was tested against mixed-wet capillary pressure data. The model was then incorporated in the University of Texas Chemical Compositional simulator called UTCHEM to compare waterflood simulations in water- and mixed-wet reservoirs. The simulation results agree qualitatively with laboratory core and field observations. The model and its implementation were also validated against sandpack experiment.
Reservoir Characterization of Ekofisk Field: A Giant, Fractured Chalk Reservoir in the Norwegian North Sea – History Match
Authors: Agarwal B. , Hermansen H. , Sylte J. E. , Thomas L. K. 
Published: December 2007

Abstract
The history match of the 3-D fluid flow model constructed on the Ekofisk Field is the focus of this study. The Ekofisk reservoir is a high porosity, low matrix permeability naturally fractured chalk. Fluid flow is largely governed by the distribution, orientation and interconnectivity of the natural fracture system associated with complex structure and reservoir distribution. Because of the impact heterogeneity has on preferential fluid flow direction, significant attention was given to capturing as much of the intrinsic heterogeneity as possible, both laterally and vertically, in the new 3-D geological model. A fairly high-resolution simulation mesh was defined for the fluid flow model, and a flow-based upscaling technique was then applied to preserve the heterogeneity from the geological to the fluid flow model. Because of the complexity of the Ekofisk Field, with its numerous faults and fracture networks, anisotropy was one of the primary attributes manipulated to achieve an individual well and field history match. However, faults and fault sealing factors, vertical permeability, pseudo relative permeability curves, bubble point pressure correlations, local permeability, and rock compressibility were also key parameters in the history match, and are presented in this paper. A brief discussion on the preliminary implementation of water-induced compaction is included.
A Preconditioned Adaptive Implicit Method for Reservoirs with Surface Facilities
Authors: Byer Thomas J. , Edwards Michael G. , Aziz Khalid 
Published: December 2007

Abstract
Fully implicit coupling of surface facilities with a reservoir model can lead to a significant increase in computing time. The focus of this paper is on methods designed to reduce the computational effort. An adaptive implicit method is coupled with a novel preconditioning method to produce an optimal strategy for fully coupled surface facility reservoir simulation.
Using Boundary Integral Methods to Couple a Semi-analytical Reservoir Flow Model and a Wellbore Flow Model
Authors: Ding Y. 
Published: December 2007

Abstract
Complex wells such as horizontal wells or multi-lateral wells are increasingly used in reservoir engineering to improve the oil recovery. A widely used semi-analytical method to study the behavior of this kind of wells, such as production performances or transient pressure responses is the source function method. However, the source method is only a particular approach to this problem, and it can be improved using boundary integral techniques.
In this paper, a mathematical model, based on the potential theory, is established for transient problem. A boundary integral equation (BIE) is introduced using the single layer heat potential. The finite (pressure drop along the well length) conductivity can be taken into account in this model. So, the wellbore flow model is adequately coupled with the semianalytical reservoir model.
The collocation and Galerkin methods are particularly studied to solve the BIE. It is shown that the Galerkin method is more efficient than the collocation method or the line source method, which can be deduced from the collocation method. Some applications of this model are also presented.
Split Tensor Operators Coupled with Quasi K-Orthogonal Grids
Authors: Edwards Michael G 
Published: December 2007

Abstract
Standard simulators that can only allow for a diagonal tensor routinely perform simulations with O(1) errors in the velocity field whenever a full tensor is present. Two approaches that permit the use of diagonal tensor 2-point flux approximations are either (a) to only employ K-Orthogonal grids or (b) split the full tensor operator. The two methods are coupled together for full tensor simulation and it is shown that the split scheme is a natural candidate for use with K-Orthogonal grids.
A New Particle Tracking Algorithm for Tracer Flow Simulation
Authors: Liu J. , Parker E. D. , Camilleri D. 
Published: December 2007

Abstract
A new particle tracking algorithm has been developed for the general case of irregular grids. Particle velocity magnitudes and directions are determined from interpolations of phase fluid fluxes across cell faces. The interpolation is based on particle coordinates in unit cube space and the edge directions of the cell. Cell transformation functions are used in transforming coordinates between physical space and unit cube space. Transformation parameters and cell edge directions are calculated once at the beginning of the simulation. Special treatments are given to cells with wells or fault connections to take into account their impacts on the particle velocity. A more accurate high-order tracking method is applied where the timestep is subdivided if a particle enters a neighboring cell or reflects during a timestep. The interpolation process then continues for the remainder of the timestep using the new cell data. A dispersion mechanism is included in the model which can be defined as either isotropic or non-isotropic.
The new algorithm has been implemented into our commercial three-dimensional, three-phase reservoir simulator, VIP. This enables the simulation of tracer flow within the framework of three-dimensional, multiphase, unsteady state reservoir simulation. The tracers are non-partitioning, and can be injected at various concentrations with either the gas or water phases. Since the algorithm is applicable for irregular grids, it becomes possible to be applied for field applications that have to use corner point grids to deal with complicated reservoir structure and geometry. The algorithm has been tested and validated on one- and two-dimensional models with analytical solutions and applied to field scale tracer applications. Three-dimensional visualization and animation of the particle paths and fronts has demonstrated the effectiveness of the tracking algorithm.
Predicting Gas Condensate Well Productivity Using Capillary Number and Non-Darcy Effects
Authors: Narayanaswamy G. , Pope G. A. , Sharma M. M. , Hwang M. K. , Vaidya R. N. 
Published: December 2007

Abstract
The objective of this work was to provide a more accurate prediction of well and reservoir performance for gas and gas condensate reservoirs by investigating near-wellbore effects. Specifically, the effects of non-Darcy flow and changes in relative permeability due to interfacial tension (IFT), and flow rate (modeled based on capillary number) on well productivity are considered. These effects are shown to be important factors affecting the productivity index (PI) of gas condensate wells. When only non-Darcy effects are considered, the condensate bank can cause an order of magnitude reduction in the PI. Hence, immediate remediation steps might be necessary for formations with high non-Darcy flow coefficients. The reduction in PI with increasing non-Darcy flow coefficient is also highly non-linear. The relative permeability improvement obtained at high capillary numbers on the other hand counteracts the PI reduction due to non-Darcy flow effects. This effect reduces the drop in PI due to condensate buildup and makes the drop in PI more gradual. Hence, both effects should be considered while studying the production performance of a gas condensate reservoir. The capillary number effect can in some cases overshadow the two-phase non-Darcy effects. Interestingly, when both non-Darcy and capillary number effects are present, the rate of decrease in the PI at or below the dew point is smaller than the case with the capillary number effect only. A case study of a lean-gas condensate reservoir, similar to the Arun field, was considered and a history match with the production data was performed. Simulation results are presented which clearly show that accurate prediction of PI based on laboratory measurements is possible using both non-Darcy and capillary number effects.
Modular Mesh Generation with Embedded Streamline Potential Grids
Authors: Edwards Michael G , Li Bin , Aziz Khalid 
Published: December 2007

Abstract
Reservoir grid generation can be simplified by decomposing the domain into a set of subdomains such that modular grid generation can be performed within each subdomain. The question of how to decompose the domain is addressed. Streamline-potential coordinates form an integral part of our domain decomposition strategy.
Steady State Solutions of Immiscible Two-Phase Flow in Strongly Heterogeneous Media: Implications for Upscaling
Authors: Stephen Karl D. , Pickup Gillian E. 
Published: December 2007

Abstract
Steady state solutions of the classical equations for immiscible two phase flow (mass balance and Darcy's Law) have been used successfully in numerical upscaling in the limits of viscous or capillary dominated flow. At low flow rates in strongly water wet or mixed wet media, capillary pressure moves the fluids rapidly at the local scale. For viscous dominated flow, once the flood front has passed, local displacement is fast compared to the change in fractional flow. For upscaling, this fractional flow can be considered as a local boundary condition. The advantage of these steady state methods is that they are much faster than conventional dynamic methods such as those of Kyte and Berry (1975), Stone (1991), requiring what is effectively a single phase solution to the flow equations.
More often, flow rates are between extremes and the above non-dynamic methods are no longer applicable. Steady state solutions can still be obtained though the numerical methods are more elaborate. Dynamic simulation can be performed until steady state is achieved with constant fractional flow boundary conditions. However, this is more time consuming than that required for conventional dynamic methods and thus a more direct method is required.
We present a fully implicit method which will obtain steady state solutions directly and thus improve the speed of calculation.
Simulations involving strong capillary forces depend heavily on internal boundary conditions defined by rapid change of either permeability or wettabillity. Continuity of capillary pressure must occur across these boundaries. The exception to this condition occurs for oil trapping (Van Duijn et al, 1995). For water wet rocks, this will happen for flow from high to low permeability rocks and the hydrocarbon will become trapped (Figure 1). In these conditions, the final steady state can be dependent on path and initial conditions. We demonstrate that capillary trapping depends not only on the form of the capillary pressure curves but also on the model boundary conditions as they vary in time.
Results from the direct implicit steady state solver mentioned above are compared to those from dynamic simulation of waterflooding (Figure 2). Effective relative permeability curves from steady state upscaling techniques are compared to contrast the different degrees of capillary trapping. It is shown that fully implicit steady state solutions will provide a good approximation to the full fine scale model (Figure 3).
Staggered in Time Coupling of Reservoir Flow Simulation and Geomechanical Deformation: Step 1 — One-Way Coupling
Authors: Minkoff Susan E. , Stone Charles M. , Arguello J. Guadalupe , Bryant Steve , Eaton Joe , Peszynska Malgorzata , Wheeler Mary 
Published: December 2007

Abstract
An isothermal, implicit, mixed finite element black oil reservoir simulator from the University of Texas is coupled to an explicit, quasistatic, nonlinear finite element solid mechanics code from Sandia National Laboratories. Both codes are 3d and parallel. The former models (in a locally conservative manner) the flow of oil, gas, and water fluid phases in the reservoir while the latter has been specialized to solve large-scale geomechanics problems involving significant inelastic deformations. In this paper we illustrate a uni-directional coupling of the two codes in which flow simulation output (pore pressures) from a 10-year test case based on the Belridge Field in California drives the geomechanics simulation for the same time period. The high-porosity, low-permeability Belridge diatomite undergoes significant compaction including 6 feet of vertical displacement at the top of the reservoir.
Simulation of Coupled Thermal/Fluid-Flow/Geomechanical Interactions in Fluid Injections
Authors: Rewis Adam , Chen Her-Yuan , Teufel Lawrence W. 
Published: December 2007

Abstract
Production/injection induced geomechanical issues in petroleum operations have been gaining more and more emphasis recently. Realistic modeling, monitoring, and controlling of flow-induced stresses are essential (and also present challenge) to reservoir management. This paper presents a numerical 2D finite-difference model incorporating the complex thermal/fluid-flow/geomechanical interactions. Non-isothermal effect (e.g., a cold-water flooding) is emphasized.
The paper describes (i) model development, (ii) model verification, (iii) simulation results, and (iv) practical implications and model limitations. Governing equations (heat flow, rock elastic deformation, and fluid flow) and the associated initial/boundary conditions are described. Control-volume-based numerical discretization/algorithm is outlined. Published analytical solutions are compared to verify the model. Effects of thermal and fluid-flow (pressurization) are isolated to show the relative importance of each mechanism.
Compared to the conventional isothermal or thermal reservoir simulators, describing flow- and thermal-induced evolution/distribution of reservoir stresses is the unique feature of the presented simulator. Simulation results indicate that thermal-induced stresses can alter reservoir stress anisotropy (in both magnitude and direction). The principal implication is that alteration and reorientation of permeability anisotropy could occur by two potential stress mechanisms: (i) permeability reduction by pore-volume compressibility effect, and (ii) permeability enhancement by flood-induced fracturing. Future work is to study the impact of the altered permeability on the sweep and recovery of a flooding project.
Advances in Coupled Geomechanical and Reservoir Modeling With Applications to Reservoir Compaction
Authors: Settari Antonin (Tony) , Walters Dale A. 
Published: December 2007

Abstract
Coupled geomechanical and reservoir modeling is becoming feasible on a full field scale. This paper describes the advances of the coupled model described previously1, its extensions for modeling compaction and the application of the model in full field studies.
The advances of the theory and numerical implementation since the original work1 make it practical to perform full field coupled studies with complex, realistic description of the geomechanical behaviour of the reservoir and shales, which allows prediction of stress changes, reservoir compaction and surface subsidence. These capabilities are demonstrated in field examples that analyze and predict classical pressure induced compaction in a gas field as well as thermally induced compaction in a heavy oil field. In both cases the methodology of interpreting the geomechanical laboratory and field data and its integration in the coupled modeling process was the key to obtaining a realistic predictive tool. The examples demonstrate that the technology is maturing to the point that conventional studies can be converted to coupled modeling on a fairly routine basis.