bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Interference Tests with Horizontal Wells
Authors: Al-Khamis M. , Ozkan E. , Raghavan R. 
Published: December 2007

Abstract
One of the common assumptions used in horizontal-well interference test analysis is to ignore fluid flow in an out of the horizontal observation well and represent it by an observation point. In some cases, the active well is also approximated by a vertical line source. Using a semi-analytical model, this paper answers three fundamental questions: i) What is the critical distance between the wells to represent the horizontal observation well by an equivalent observation point? ii) Where should the equivalent observation point be placed along the horizontal well? iii) Under what conditions can the active well be approximated by a vertical line source and the exponential integral solution be used for the observation well responses? Two correlations are presented to simplify the analysis of horizontal well interference tests. Example applications are presented and error bounds are documented.
Pressure Transient Derivative Signatures In Presence of Stratiform Super-K Permeability Intervals, Ghawar Arab-D Reservoir
Authors: Gill Harmohan S. , Al-Zayer Rayed 
Published: December 2007

Abstract
This paper describes case studies of observed pressure derivative signatures in the presence of stratiform Super-K permeability intervals in Ghawar field, Arab-D oil reservoir. The case studies (presented in order of increasing complexity) include: 1) an open-hole vertical well intersecting the Super-K interval, 2) a slant horizontal well intersecting the Super-K interval and, 3) a horizontal well at the top of a layered reservoir, not in contact with the Super-K interval and separated from the Super-K interval by low permeability layers.
The stratiform Super-K permeability intervals in Ghawar can be visualized as being like horizontal pancakes of multi-darcy permeability. Since these Super-K intervals are not continuous but rather show up as patches of high permeability, the typical effect on the pressure derivative of a vertical open-hole well is that of a radial composite system.
The most complex derivative signature is observed when a horizontal well is separated from the non-intersecting Super-K interval by low permeability layers. It is very easy to misinterpret this derivative signature without integrating all the available geological and production log data.
The derivative signatures are demonstrated by numerically simulated responses of actual case studies. The importance of identifying these pressure derivative signatures is illustrated in this heterogeneous, multiphase, layered, reservoir where data quality is sometimes poor due to wellbore phase redistribution.
Analytical Solution to the Transient-Flow Problems for a Well Located near a Finite-Conductivity Fault in Composite Reservoirs
Authors: Rahman N. M. Anisur , Miller Michael D. , Mattar Louis 
Published: December 2007

Abstract
This study presents a new analytical solution to the transient flow problem of a well located near a finite-conductivity fault in a two-zone, composite reservoir. The solution accounts for transient flow within the fault, which has been disregarded in all previous studies. The solution is obtained with the Laplace and Fourier transformations, and is verified by comparing a number of its special cases with those available in the literature. A detailed computational procedure is outlined, which is easy to implement in software, and not numerically challenging.
Robust Determination of the Pore Space Morphology in Sedimentary Rocks
Authors: Silin Dmitry B. , Jin Guodong , Patzek Tad W. 
Published: December 2007

AbstractWe present a new robust approach to study the morphology (shapes and connectivity) of the pore space of a sedimentary rock. Our approach is based on the long-established, fundamental concepts of mathematical morphology. In particular, we propose an efficient and stable algorithm which distinguishes between the "pore bodies" and "pore throats," and establishes their respective volumes and connectivity. Our algorithm is extensively tested on the 3D digital images of computer-generated and natural sandstones. The algorithm tests on a pack of equal spheres, for which exact results can be verified visually, confirm its stability. Computer-generated pore space images are used to investigate the impact of image resolution on the algorithm output.Presently, the proposed algorithm produces a stick-and-ball diagram of the rock pore space. One of distinctive features of our approach is that no image thinning is applied. Instead, the information about the skeleton is stored through the maximal balls associated with each voxel. These maximal balls retain information about the entire pore space. Comparison with the results obtained by a thinning procedure preserving some topological properties of the pore space shows that our method produces more realistic estimates of the number and shapes of pore bodies and pore throats, and the pore coordination numbers.Based on the information about the maximal ball distribution, we simulate mercury injection and compute a dimensionless drainage capillary pressure curve. We demonstrate that the calculated capillary pressure curve is a robust descriptor of the pore space geometry and, in particular, can be used to determine the quality of computer-based rock reconstruction.
A Physical Model to Explain the First Archie Relationship and Beyond
Authors: Shang Bruce Z. , Hamman Jeffry G. , Caldwell Donald H. 
Published: December 2007

Abstract
We report a new model relating porosity and formation resistivity factor. This model not only explains both Archie and non-Archie behaviors with non-conductive minerals, but also complies with meaningful physical bounds. We define an equivalent rock element aligned with the direction of measurement, in which the pore structure is comprised of two orthogonal components. One is oriented along electrical potential gradient and contributes most efficiently to current flow. The other is perpendicular to the gradient and contributes least efficiently per unit pore volume. The ratio of the former over the latter is defined as "pore structure efficiency". By adjusting pore structure efficiency, any rock can be equivalently represented. Formation resistivity factor can then be expressed as a function of total porosity and pore structure efficiency. Upon analyzing relevant factors in reservoir rocks, we approximate pore structure efficiency as a simple linear or power function of porosity. This leads to a new theoretical relationship between formation resistivity factor and porosity that: explains and agrees with Archie's generalized first equation for a geologically realistic porosity range from 0 to 40%,explains non-Archie phenomena, e.g. noticeable curvature in dual logrithm coordinate space of formation factor versus porosity,is consistent with physical bounds from 0 to 100% porosity, e.g., the magnitude of slope is never smaller than 1, and tends to be 1 as porosity approaches 100%,generalizes multiple porosity domain system into one transitionally smooth description,contains a term representing pore structure efficiency independent of porosity that can be potentially used for fracture analysis,is applicable to both isotropic and anisotropic media by definition.
A Model to Correlate Permeability With Efficient Porosity and Irreducible Water Saturation
Authors: Shang Bruce Z. , Hamman Jeffry G. , Chen Hung-Lung , Caldwell Donald H. 
Published: December 2007

Abstract
This paper introduces a new permeability estimation method using the equivalent rock element model which consists of two pore components, one parallel and the other perpendicular to the potential gradient. Both formation resistivity factor and permeability are related to porosity and pore structure, but permeability also depends on pore scale and internal specific pore area. In water wet rocks, irreducible water saturation is a parameter closely related to pore size or scale and internal specific area. Irreducible water occupies space in both parallel and perpendicular pore components and hinders fluid passage. The relative volume occupied in each component varies with many factors such as pore scale and interconnection, fluid properties, mineralogy and wetting characteristics of the mineral/fluid system. This non-uniform occupancy is approximated by a simple power function. An efficient flow porosity is defined by modifying efficient electrical porosity using irreducible water saturation to account for scale and specific pore area. The correlation between efficient flow porosity and permeability is much greater than those in many of the commonly used methods. This method has been applied to several sets of cores from different parts of the world. Better correlations between measured and estimated permeability have been obtained in all datasets compared with other published approaches, such as porosity versus logarithm of permeability, Kozeny-Carman, Wyllie-Rose, and Timur methods.
The Results of Increased Fracture Conductivity on Well Performance in a Mature East Texas Gas Field
Authors: Flowers J. R. , Hupp M. T. , Ryan J. D. 
Published: December 2007

Abstract
In our industry's never-ending search to cut cost, there has been an alarming trend in the design of hydraulic fractures. This trend is the shift to lower fracture conductivity, which is being achieved through reduced proppant concentrations and the selection of less expensive, inferior proppants. This change is most evident in tight gas completions where even very low fracture conductivities are assumed to achieve infinite-acting fractures. Obviously, these changes can reduce the overall cost of the fracture treatment, but at what cost to well performance? This paper will review the production and economic impact of altering fracture conductivity in 18 low permeability wells in a mature East Texas gas field.
Most traditional conductivity calculations are problematic because they are based on laboratory-generated numbers and ignore the effects of non-Darcy and multi-phase flow. While most frac design engineers routinely and correctly include 50% damage introduced to the proppant pack by polymers, they continue to dismiss the additional 90% conductivity reductions that can be induced by non-Darcy and multi-phase flow. This leads to a drastic underestimation of the pressure drop within the proppant pack, and consequently, production results that fail to meet expectations.
The purpose of this paper is to demonstrate that these rate-induced conductivity reductions are real and that production improvements can be achieved through increased conductivity, although conventional "Darcy" analysis may erroneously indicate otherwise. In this case study, production results from eighteen wells located in a mature gas field in East Texas will be presented. Nine wells were completed with designs based on traditional Darcy flow models and nine offset wells utilized a new design to incorporate non-Darcy and multi-phase flow effects. In addition to production results, economic analyses are provided to show that the increased job cost is quickly recovered with improved production. Estimated ultimate recovery for each well is presented in an attempt to quantify the long term effects of increased conductivity. These analyses demonstrate that reducing fracture conductivity, as a cost savings measure, can significantly reduce both cash flow and net present value of the well. Production results to date indicate that the wells receiving the higher conductivity fractures will produce an average of 2 BCF/well incremental reserves for an additional investment of less than $50,000/well.
Avoiding Proppant Flowback in Tight-Gas Completions with Improved Fracture Design
Authors: Canon Javier M. , Romero Diego J. , Pham Tai T. , Valko Peter P. 
Published: December 2007

Abstract
In this paper we describe the possibility and benefits of incorporating the stability analysis of the proppant pack during the design stage of hydraulic fracturing treatments.
After the well is treated and cleaned up, the flowback of proppant from a fracture-treated formation is highly undesirable for several reasons, including possible damage to the wellhead and flowlines, operational complications, and last but not least, decrease in well-productivity. The issue has been studied on an empirical basis and the most important factors have been determined. Nevertheless, qualitative models suggested so far seem to work only under limited conditions and currently there is no clear methodology for predicting the occurrence of proppant flowback while designing the treatment.
In this work we review previously suggested prediction methods and analyze the proppant flowback patterns experienced in 24 South-Texas tight-gas completions. As a result of the study we conclude that the predictive power of the available models is not satisfactory and the implications for "proppant stability control agents" are not based on convincing evidence. A new semi-mechanistic model is proposed that shows reasonable agreement with both laboratory and field data. A methodology is suggested to incorporate the proppant flowback prediction at the fracture design stage. The suggested methodology is based on the concept of "minimum necessary departure from optimality to satisfy technical constraints", in this case the constraint being to keep the likelihood of proppant flowback under a certain threshold.
Effective Proppant Flowback Control Following Hydraulic Fracturing Treatments in Shallow Reservoirs
Authors: Stephenson Chris J. , Crabb Terry M. , Orrego Guillermo Villa , Khachatrian Mikael B. 
Published: December 2007

Abstract
Proppant flowback within shallow wells, as with all wells, can be a significant problem in the oil and gas industry. Under the typical low-stress and low-temperature conditions found in shallow formations, many of the current products and processes to control proppant flowback often fail or have only limited success. As such, improved or alternative technology and procedures are constantly being sought. One such technology is the development of a deformable proppant for use under low closure stress conditions. Laboratory testing of this ‘low-stress’ (LS) deformable proppant, blended with typical fracturing sand, has shown 20 fold increases in flowrate and 10 fold increases in pressure-drop are attainable without proppant pack failure, while still maintaining or in some cases increasing fracture conductivity.
Furthermore, this ‘low-stress’ (LS) deformable proppant has been successfully applied in shallow reservoirs with typical closure stresses +/-500 psi and bottom-hole temperatures of +/-100°F. Several case histories, along with the development of equipment and monitoring procedures required to facilitate field application will be discussed.
Field Verification: Invert Mud Performance from Water-Based Mud in Gulf of Mexico Shelf
Authors: Klein Aaron L. , Aldea Catalin , Bruton James R. , Dobbs Williams R. 
Published: December 2007

Abstract
A uniquely designed water-based mud (WBM) was used in two shelf areas of the Gulf of Mexico to drill highly reactive gumbo sections. The drilling performance and inhibition in these shale intervals resembled that of synthetic-based muds (SBM) previously used in offset wells. Owing to new environmental regulations, obtaining the drilling performance characteristics of a synthetic-based fluid and the stability of a water-based fluid is a high priority for Gulf of Mexico operators.
A special characteristic of this fluid is its ability to deliver SBM-like shale inhibition without using any salts, through an ideal combination of a polyamine shale inhibitor, a polymeric encapsulator and an anti-accretion additive.
This paper presents field data comparing the drilling performance and the inhibition in gumbo shale sections between the new WBM and previously used SBM. With instantaneous rates of penetration up to 85% higher than synthetic-based fluids used in similar well sections, the average time required to drill identical intervals was reduced dramatically. No accretion or bit balling was noted on bottomhole assemblies during bit runs, and the cuttings drilled were well encapsulated and protected from hydration. Economic savings were realized by reducing the drilling time and by not requiring the essential waste management equipment and engineering associated with SBM cuttings discharge. Furthermore, the new high-performance WBM was easily prepared at the wellsite using seawater, which also translated into cost savings by reducing the volumes handled by the workboats.
These field applications demonstrate that this uniquely designed water-based fluid can effectively replace invert-emulsion fluids in many highly reactive shale sections without sacrificing drilling performance or increasing environmental risk.
Towards Truly Permanent Intelligent Completions: Lifelong System Survivability Through a Structured Reliability Assurance Process
Authors: Veneruso A. F. , Kohli H. , Webster M. J. 
Published: December 2007

Abstract
This paper describes a structured reliability assurance process to quantify and optimize the reliability of electric permanent monitoring and control systems for application in intelligent completions. Although reliability is essential to unlock the potential of the intelligent well, there are challenges in terms of the long lifetimes involved, high risks and high costs associated with failure, and the difficulty of diagnosing problems, retrieving failed parts, and learning lessons from equipment within the reservoir.
A structured reliability process is described that is based on innovative techniques to address these inherent challenges and help overcome barriers many perceive as impediments to the acceptance and growth of this important technology. These techniques have been developed and proven in quite different areas of technology such as aerospace, defense, biology, and health science as well as the risk assurance industry.
A New Optimization Methodology for Portfolio Management
Authors: April J. , Glover F. , Kelly J. , Laguna M. 
Published: December 2007

Abstract
A new portfolio optimization software system simultaneously addresses financial return goals, catastrophic loss avoidance, and performance probability. The innovations embedded in the system enable users to confidently design effective plans for achieving financial goals, employing accurate analysis based on real data. Traditional analysis and prediction methods are based on mean variance analysis – an approach known to be faulty. The new software system takes a much more sophisticated and strategic direction. State-of-the-art technology integrates simulation and metaheuristic optimization techniques and a new surface methodology based on linear programming into a global system that guides a series of evaluations to reveal truly optimal investment scenarios.
Portfolio analysis tools are designed to aid senior management in the development and analysis of project portfolio strategies, by giving them the capability to assess the impact on the corporation of various investment decisions. To date most of the commercial portfolio optimization packages have been relatively inflexible and are often not able to answer the key questions asked by senior management. In this paper we will present new techniques that increase the flexibility of optimization tools and deepen the types of portfolio analysis that can be carried out. We also include some examples applied to P&E portfolios.
Gas Storage and Flow in Coalbed Reservoirs: Implementation of a Bidisperse Pore Model for Gas Diffusion in Coal Matrix
Authors: Shi Ji-Quan , Durucan Sevket 
Published: December 2007

Abstract
Unipore diffusion models are widely used for modelling gas transport in coal matrix in conventional dual-porosity coalbed reservoir simulators. The unipore models implemented in conventional coalbed reservoir simulators assume that free gas phase is negligible and gas exists only in adsorbed state in coal matrix. In low-rank coals, however, a substantial amount of free gas may exist in the macropores of coal matrix.
There is strong laboratory evidence that many coals exhibit bi- or multi-modal pore structure. This paper describes the implementation of a bidisperse pore-diffusion model in a coalbed reservoir simulator. In the bidisperse model, gas adsorption is assumed to take place only in the micropores, with the macropores providing storage for free gas, as well as tortuous paths for gas transport between the micropores and cleats. Gas production performance from a sub-bituminous Powder River Basin coalbed reservoir has been studied using the in-house Imperial College coalbed reservoir simulator. The implementation of the triple-porosity formulation in the simulator overcame the reported inconsistency between field gas production rates and predicted rates obtained using conventional dual-porosity simulators. With the introduction of an appropriate storage volume of free gas in the macropores, the predicted increase in gas production rates are consistent with the published field data.
Role of Convective Mixing in the Long-Term Storage of Carbon Dioxide in Deep Saline Formations
Authors: Ennis-King Jonathan , Paterson Lincoln 
Published: December 2007

AbstractStorage of carbon dioxide in deep formations is being actively considered for the reduction of greenhouse gas emissions. Relevant experience in the petroleum industry comes from natural gas storage and enhanced recovery using carbon dioxide, but this experience is over a time scale less than the hundreds or thousands of years required for carbon dioxide storage. On these long time scales different mechanisms need to be considered.In the long-term the dominant mechanism for dissolution of carbon dioxide in formation water is convective mixing rather than pure diffusion. This arises because the density of formation water increases upon dissolution of carbon dioxide, creating a density instability. Linear stability analysis has been used to estimate the time required for this instability to occur in anisotropic systems. For sufficiently thick formations with moderate vertical permeability, this time is years to decades. Further approximate analysis shows that the time needed for the injected gas to dissolve completely is typically much longer, of the order of hundreds to thousands of years, depending on the vertical permeability. This theoretical analysis is found to be in broad agreement with the results of fine scale reservoir simulations. Laboratory experiments on an analogous system demonstrate the same phenomena.
Completion of Aconcagua Field With a Dual Derrick Drilling Unit
Authors: Geyelin Jean-Louis , Clergier Alberic , Bouget Ronan , Manchon Xavier 
Published: December 2007

Abstract
Dual derrick drilling units were claimed to reduce drilling time by +/- 25%, taking advantage of their enhanced handling capacity. These statements were issued bearing in mind drilling activities.
The Aconcagua Field - operated by Total E&P USA, Inc. - is located on Mississippi Canyon 305 and was completed by means of a dual derrick drilling unit (DDDU).
This paper describes the lessons learned to complete deep water, multi-zone, sand controlled, intelligent wells by using a DDDU in ultra deepwater.
Careful planning and rigorous organization were essential to take full advantage of the dual derrick capabilities, and run simultaneous completion phases. Permanent procedures and operational improvement during the four month campaign allowed to develop a learning curve. Substantial cost and time savings were achieved while delivering wells with excellent production performance.