bluuebunny/crossref_metadata_2025_split huggingface dataset:
Annulus Unloading Rates as Influenced by Wellbore Storage and Skin Effect
Authors: Ramey Henry J. , Agarwal Ram G. 
Published: December 2007

Abstract
The modern trend in well testing (buildup or drawdown) bas been toward acquisition and analysis of short-time data. Pressure data early in a test are usually distorted by several factors that mask the conventional straight line. Some of the factors are wellbore storage and various skin effects such as those due to perforations, partial penetration, non-Darcy flow, or well stimulation effects. Recently, Agarwal et al. presented a fundamental study of the importance of wellbore storage with a skin effect to short-time transient flow. This paper further extends the concept of analyzing short-time well test data to include solutions of certain drillstem test problems and of cases wherein the storage constant, CD, undergoes an abrupt change from one constant value to another. An example of the latter case is change in storage type from compression to liquid level variations when tubinghead pressure drops to atmospheric Arks production. The purpose of the present paper is to: production. The purpose of the present paper is to:
- present tabular and graphical results for the sandface flow rate, qsf, and the annulus unloading rate, qa, as a fraction of the constant surface rate, q, and
- illustrate several practical well test situations that require such a solution.
Results include a range of values of the storage constant, CD, and the skin effect, s, useful for well test problems. problems. Annulus unloading or storage bas been shown to be an important physical effect that often controls early well test behavior. As a result of this study, it appears that interpretations of short-time well test data can be made with a greater reliability, and solutions to other storage-dominated problems can be obtained easily. Techniques presented in this paper should enable the users to analyze certain short-time well test data that could otherwise be regarded as useless.

Introduction
In a recent paper, Agarwal et al. presented a study of the importance of wellbore storage with a skin effect to short-time transient flow. They also presented an analytical expression for the fraction presented an analytical expression for the fraction of the constant surface rate, q, produced from the annulus
Although the rigorous solution (inversion integral) and long- and short-time approximate forms were discussed, neither tabular nor graphical results ofdpwD the annulus unloading rate, CD, were given.dtD It now appears that such solutions are useful in certain drillstem test problems and in cases wherein the storage constant, CD, changes during a well test. An example is change in storage type from compression to liquid level change when tubinghead pressure drops to atmospheric during production. pressure drops to atmospheric during production. The purpose of this study is to (1) present tabular and graphical results for the sandface flow rate and the annulus unloading rate and (2) illustrate several practical well test situations that require the practical well test situations that require the solutions.
Three-Phase Well-Level Production Allocation at Prudhoe Bay
Authors: Bergren F. E. , Lagerlef D. L. , Feldman Scott 
Published: December 2007

Summary
Three-phase production-allocation programs have continuously evolved in the Prudhoe Bay Eastern Operating Area (PBEOA) over the past 19 years. These programs are necessary because the actual production rate of a well can be measured only when a well is being tested. Since each well is tested for about 6 hours per week, some method of estimating well production rates in real time while the well is not being tested is required. These estimates are used to optimize well and field production as surface processing and product shipping constraints vary. These estimates are also used to estimate field production rates in real time, track well performance, and allocate production volumes to wells for accounting and reservoir management purposes.
Rate tables for most naturally flowing wells and all gas lifted wells are based upon the Fetkovich inflow performance model and tubing performance relationships (TPR&apos;s) developed from various tubing hydraulics models. Specialty rate table programs allow engineers to allocate production to wells which always produce at the same choke setting, wells which are in the process of gassing out, and to automatically allocate wells which maintain consistent performance. A recent upgrade of the allocation system, utilizing current generation computer hardware, communications hardware, and software has resulted in a 60% reduction in engineering time required for production allocation.
The allocation process discussed here can be applied to many other fields to improve the link between field well test data and the optimization of field production rate, estimation of well and field production rates in real time, well performance tracking and allocation of field production to wells for reservoir management and accounting purposes.
Explosive Termination of a Wild Well Evaluation of a Concept
Authors: McLamore R.T. , Suman G.O. 
Published: December 2007

A concept to terminate a wild well by detonating a subsurface explosive charge placed in a relief well near the wild well has been investigated and found to be feasible. The study described in this paper dealt with the application of conventional chemical explosives; however, the concept is equally valid for nuclear explosives.

Introduction
In March, 1970, the Shell Cox No. 1 well near Jackson, Miss., blew out during drilling, caught fire, and eventually cratered and extinguished itself. The well was a 22,000-ft high-pressure sour-gas well. Flow rates while the well was blowing out were estimated to range from 20 to 100 MMcf/D. Data gathered on site indicated that the crater had plugged at a relatively shallow depth, causing an underground blowout.
Plans were developed to drill a relief well to total depth. Drilling time of this well was estimated to be 12 to 18 months. The great depth, the directional drilling problems, the presence of sour gas, and the tightness of the formation were severe conditions that dictated the development of a novel concept to kill the well quickly.
Two such concepts were developed. The first consisted of (1) drilling an intercept well to a depth of approximately 10,000 ft in such a way that the casing in the intercepting well was in contact with the casing in the Cox No. 1 well, (2) cementing the two strings together, (3) perforating the strings to create communication, and (4) pumping cement into the wild well to kill it. This is the technique that was eventually used.
The second concept consisted of (1) drilling a 10,000-ft intercept well converging to within 15 ft of the wild well, (2) washing a large cavity at the bottom of the hole, (3) pumping conventional explosives into the cavity, and (4) detonating on command. The explosion would create a larger cavity, crush and rubble the rock, collapse and shatter the casing in the wild well, and stem the flow of gas at that depth. The purpose of this paper is to discuss the program that was carried out to evaluate this concept.
Calculations, using finite-difference programs, were made to evaluate the effect of explosive properties and rock properties on the cratering and ground motion associated with the detonation so that the shot could be properly designed. In addition, an explosive formulation was developed that met the requirements for safe handling and pumping on the surface and detonation in a high-pressure and high-temperature environment.
From the study it has been concluded that the concept of using explosives to terminate a wild well is feasible. Although the concept is untried to date in this country, the Russians have demonstrated the soundness of it by killing two wild gas wells using nuclear explosives.
Project Planning Project Planning After the explosive kill concept was conceived, the following program was developed to evaluate it and to bring it to completion, if necessary.
Phase 1 Determine the feasibility of explosively terminating Cox No. 1 and develop specific proposals to accomplish the job.
JPT
P. 1084
DPARS Production and Reserves System: Evolution of a Corporate Tool
Authors: Borcholt Matthias , Robertson G. D. 
Published: December 2007

Summary
We describe the evolution of a customer-driven, fit-for-purpose database tool that intelligently combines reserves, production, entitle-ment/sales, capital expenditures (Capex), operating expenditures (Opex), well scheduling, and separator test data. The tool, Deminex Production and Reserves System (DPARS), evolved from a singleuser application on a portable personal computer (PC) to a networked, multiuser, corporate tool used worldwide in a midsize international oil and gas E&P company.
The Architecture of a Plug-and-Play Kernel for Oilfield Software Applications
Authors: Ward V. L. , Seaton C. P. 
Published: December 2007

Summary
It is now common practice for engineers to use PC software to design and evaluate oilfield services. Rapidly changing technology in PC software has made it necessary for organizations to release new applications quickly to remain competitive. We designed a plug-and-play kernel for the computer aided design and evaluation (CADE) applications to reduce development time and time to market. Our paper discusses the kernel used in the CADE software in detail.
The Application of World Wide Web Technology in a Learning Organization
Authors: Evans D. C. 
Published: December 2007

Summary
In mid-1995, the departments responsible for drilling, completion, and workover operations on behalf of three North Sea subsidiaries of a major multinational oil company integrated into a single North Sea drilling group (NSDG). As part of a global drilling organization, the NSDG now serves the three business units in the North Sea area by providing a shared-service capability to its respective exploration and asset-management teams. One of the fundamental problems that the new group faced was how to share knowledge and expertise effectively among team members in several locations. A solution to this problem was essential for the group to achieve its goals of minimizing total life-cycle well costs, increasing efficiency through the integration of existing teams, and continuing to develop as a center of excellence within a global drilling operations network.
The group identified World Wide Web (WWW) technology as a cost-effective solution that could provide a mechanism for the transfer of engineering technology and learnings, both within the group and throughout the worldwide drilling community. The WWW has proved to be a powerful new medium for the communication of dynamic information, such as reports, business objectives, performance measures, policies, and other reference material, as well as being a valuable source for technical information that otherwise might have been overlooked in our decision-making processes.
This approach has enhanced our ability to optimize the use of existing resources, yielding significant economic benefits to each of the participating customers. A specific example is the role of the WWW in the continuing development and implementation of the drilling-management system (DMS), an organizational learning tool now being introduced widely to optimize the planning, implementation, and evaluation of wells.
Integration of Old and New Measurements To Optimize Redevelopment of the Lower Lagunillas Reservoir of Bloque IV, Lake Maracaibo, Venezuela
Authors: Bryant I. D. , Baygün Bülent , Herron M. M. , Matteson Abigail , Ramamoorthy Raghu , Stewart Lisa , Tariq S. M. , Coll Carolina , Cordova Pedro , de Villarroel Helena Gamero , Hernández Luis , Jimenez Zulay , León Karmele , Rondón Luis 
Published: December 2007

Summary
The Lower Lagunillas of Bloque IV of the Bachaquero field is a supergiant reservoir that has been in production since 1956. We have carried out a pilot reservoir characterization study in the central part of the field, in which we have integrated all the available data into three-dimensional (3D) reservoir simulation models whose purpose is to optimize redevelopment of the area with horizontal wells.
An analysis of the history of production was undertaken to gain an insight into the reservoir dynamics. This analysis indicated the inefficiency of gas injection in providing pressure support to the pilot study area and demonstrated the presence of active aquifer encroachment from the south. Anomalies in production behavior and fluid characteristics indicate both lateral and vertical compartmentalization of the reservoir.
We have integrated Fourier transform infrared (FTIR) measurements of mineralogy from old cores with a comprehensive logging suite in a new well to re-evaluate older, sparse logging suites. The application of a mineral-based log evaluation and high-resolution processing of the new logs has led to a significant increase in estimates of oil initially in place in the study area. We have used a novel approach to estimate permeability in all wells in the study area. Combining these new evaluations with a revised geological model enabled us to recognize 11 geological layers throughout the area. Formation pressure measurements confirm that partial barriers to vertical communication exist between most of these layers. Cased hole saturation measurements and historical production data indicate an uneven sweep of these layers, such that five layers contain bypassed oil that could be recovered by horizontal wells. We have constructed very detailed simulation models that describe the lateral and vertical variation in petrophysical properties of each of these layers. These models have been used to select the optimum locations for horizontal wells and to optimize their drilling sequence and design. It is estimated that each of these wells could recover 1 to 1.5 million stock-tank barrels (STB) within 5 years.
The first well drilled as a result of this study has produced dry oil at rates up to 469 BOPD from a zone not previously considered as a pay zone.
Constrained Derivatives in Natural Gas Pipeline System Optimization
Authors: Flanigan Orin 
Published: December 2007

Here is a promising new method for optimizing both the facilities and the operations of integrated natural gas pipeline systems. The balancing-of-nodes calculation method is used as a system model and the method of constrained derivatives is used in conjunction with this model to optimize the system represented.

Introduction
Historically, differential calculus has been a prime tool in optimization work. When certain conditions are present, differential calculus can be a simple and powerful tool. These conditions are: powerful tool. These conditions are:
(1) The system can be described by a set of continuous analytical equations.
(2) The system contains no constraints.
(3) The system equations are differentiable.
When these (and sometimes other) conditions are met, the classical approach is to take the first derivative of the system equations with respect to certain specified variables. These derivatives are set equal to zero and the resulting equations are solved for their various roots. The second derivatives are then used to evaluate whether the roots are maxima, minima, or points of inflection. A physical representation of a simple unconstrained system is a single hill. Differential calculus will lead us to the top of the hill.
Unfortunately, the range of actual problems to which this procedure can be applied is quite limited. Most problems have at least some constraints; and many systems of interest are severely constrained. Some examples of these constraints are: (1) the pressure must not exceed a certain value; (2) the temperature must be between certain limits; (3) limits are imposed on the flow rates.
These constraints to the system may be visualized as a series of fences on the hill that usually prevent an explorer from reaching the top of the hill. The optimum or maximum is the highest point on the hill that can be reached without crossing the fence. In this case, the classical differential calculus approach is useless.
Shale Compaction
Authors: Smith J.E. 
Published: December 2007

Abstract
The compaction of shales or other fine-grained compressible rocks is described by a mathematical model, and specific solutions are presented graphically. The model treats the presented graphically. The model treats the upward and downward movements of the water the solid matrix in very extensive, uniform, flat-lying units. It may readily be adapted treat the compaction of sands. The principal elements of the model are:
(1) continuity equations for the water and solid matrix;
(2) Darcy's law;
(3) an expression for the fluid potential;
(4) an equation for the total vertical stress;
(5) an empirical relationship between porosity and the difference between the total vertical stress and the fluid pressure; and
(6) an empirical relationship between permeability and porosity.
From these elements an expression is derived for the porosity within the unit in terms of the space and time coordinates and boundary conditions, for the approximation that the densities of the water and the solid matrix are constant. Numerical solutions for the fluid pressure, the total vertical stress, the pressure, the total vertical stress, the porosity, the permeability, and the velocities porosity, the permeability, and the velocities of water and solid matrix were obtained as profiles through the unit at close time intervals, profiles through the unit at close time intervals, and representative results are displayed. The events followed are:
(1) shale sedimentation;
(2) a time lapse following shale sedimentation;
(3) sedimentation of a normally pressured unit over the shale unit; and
(4) a final time lapse with no sedimentation.
Two boundary conditions for the base of the shale unit are considered:
(1) the underlying unit is impermeable, and
(2) the underlying unit is a normally pressured sand.
In the latter case, water flows both upward and downward out of the compacting unit. The solutions show that pore water pressures much greater than normal are obtained and may persist for tens or hundreds of millions of years. It is also found that a shale unit rapidly buried beneath a thick normally pressured sand develops a zone near the sand-shale boundary of reduced porosity and permeability in which the pore water pressure permeability in which the pore water pressure gradient is very large.

Introduction
The presence of low density overpressured shales or mudstones in a sedimentary sequence influences the operations of petroleum exploration, drilling and production. During the exploration phase such low density fine-grained rocks influence the interpretation of seismic and gravity surveys. During the drilling of prospects, the mud casing and log programs and prospects, the mud casing and log programs and safety are affected by high pressures. During production, the possible influx of shale water production, the possible influx of shale water requires investigation.
Three-Dimensional Reservoir Description From Multiwell Pressure Data and Prior Information
Authors: He Nanqun , Reynolds Albert C. , Oliver Dean S. 
Published: December 2007

SummaryBayesian estimation techniques are applied to generate three-dimensional permeability and porosity fields conditioned to prior means, variograms, hard data and/or multiwell pressure data. A posteriori variances are generated to obtain a measure of the uncertainty in the rock property fields, or equivalently, a measure of the variability in realizations of the rock property fields. These a posteriori variances can also be used to quantify the value of data, i.e., to determine the reduction in uncertainty achieved by adding a particular type of data. A key ingredient of our methodology is the development and implementation of an efficient procedure to estimate sensitivity coefficients for three-dimensional single-phase flow problems.
The Permeability Variogram from Pressure Transients of Multiple Wells: Theory and 1-D Application
Authors: Yortsos Yanis C. , Al-Afaleg Nabeel 
Published: December 2007

Summary
This paper presents a new approach for the estimation of the large-scale correlation function of reservoir heterogeneity from the analysis of the pressure transient response of multiple wells. The approach is based on the theory of small fluctuations of the logarithm of the permeability and models the response of the "ensemble-average pressure", obtained by averaging the pressure response of multiple well tests. A non-local difFusivity equation for the ensemble-average pressure, which incorporates directly the permeability correlation function, is obtained, from the analysis of which the permeability semi-variogram of the reservoir can be constructed in principle. We consider a particular application to 1-D geometries, where a type-curve is also derived for the case of an exponential correlation function. Numerical simulations results support the applicability of the method.
Integrated Reservoir Characterization Study of a Carbonate Ramp Reservoir: Seminole San Andres Unit, Gaines County, Texas
Authors: Wang F. P. , Lucia F. Jerry , Kerans Charles 
Published: December 2007

Summary
One of the important issues in constructing geologic and reservoir models is to define geologic frameworks. A geologic framework is fundamental to defining flow units, to interpolating well data, and thereby to modeling fluid flow. For the Seminole San Andres Unit (SSAU), the high-frequency cycles (HFC's) and rock-fabric facies identified on outcrop analogs and cores were used to correlate wireline logs. Reservoir and simulation models of the outcrop and a two-section area of SSAU were constructed with rock-fabric units within the HFC's as a geologic framework. Simulations were performed using these models to investigate critical factors affecting recovery.
HFC's and rock-fabric units are the two critical scales for modeling shallow-water carbonate ramp reservoirs. Descriptions of rock-fabric facies stacked within HFC's provide the most accurate framework for constructing geologic and reservoir models, because discrete petrophysical functions can be fit to rock fabrics and fluid flow can be approximated by the kh ratios among rock-fabric flow units. Permeability is calculated using rock-fabric-specific transforms between interparticle porosity and permeability. Core analysis data showed that separate-vug porosity has a very strong effect on relative permeability and capillary pressure measurements.
The effect of stratigraphic constraints on stochastic simulation was studied. Geologic models generated by a conventional linear interpolation, a stochastic simulation with stratigraphic constraints, and a stochastic simulation without stratigraphic constraints were compared. The stratigraphic features of carbonates can be observed in stochastic realizations only when they are constrained by rock-fabric flow units. Simulation results from these realizations are similar in recovery but different in production and injection rates.
Scale-up of permeability in the vertical direction was investigated in terms of the ratio of vertical permeability to horizontal permeability (kvh). This ratio decreases exponentially with the vertical gridblock size up to the average cycle size of 20 ft (6.1 m) and remains at a value of 0.06 for a gridblock size of more than 20 ft (&gt;6.1 m), which is the average thickness of HFC's. Simulation results showed that the critical factors affecting recovery efficiency are stacking patterns of rock-fabric flow units, kvh ratio, and dense mudstone distribution.