bluuebunny/crossref_metadata_2025 huggingface dataset:
Estimating Perforation Flow Performance From Variations in Indentation Hardness
Authors: Halleck P. M. , Poyol Edmund , Santarelli F. J.
Published: December 2007

We mapped the hardness of the rock surrounding shaped-charge perforations with an indentation technique based on the Brinell method. We fired conventional perforators (3.2-g explosive weight) into a friable sandstone (approximately 6.9 MPa unconfined compressive strength) under 10.3 MPa effective stress. We observed substantial reductions in hardness extending more than 10 cm away from the perforation tunnel. The severity and extent of the damage was not uniform and was greatest near the perforation at the entrance hole, decreasing toward its tip. A comparison with a similar test with a drilled hole demonstrated that the observed damage was caused by the impact of the shaped-charge jet on the rock. The extent of the damage was independent of the diameter of the rock specimen used during the test. By assuming that permeability reduction is proportional to mechanical damage (i.e., hardness reduction), we obtained numerical simulations of flow rate and distribution. The calculated flow rates were consistent with those measured after perforating the samples. Careful analysis of the data suggested that the mechanical damage and permeability reduction were related to increases in finer particle sizes and smaller pore sizes that were observed by other workers. These led to increased tortuosity in the flow paths.

The classic vision of a thin, uniform crushed zone with reduced permeability surrounding the perforation tunnel did not seem to apply in the case of more friable materials. The calculated permeability map suggested that much of the flow occurred at the perforation tip for such rocks, indicating that downhole conditions were probably better simulated by linear-flow-rather than radial-flow-model targets. Finally, the radial extent of the damaged zone around the perforation tunnel raised questions concerning the interaction between adjacent perforations in a vertical plane when large shot densities were used.
Determining and Averaging Gas Reservoir Pressures
Authors: Doyle R.E. , Young T.S.
Published: December 2007

The results of this study indicate that the nearest fit to a linear gas material balance plot (the best estimate of initial gas in place) is obtained by correcting the estimated average well pressure for asymmetrical drainage effects, then weighting the individual average pressures by the pore volume drained by each well. A significant error may result in the estimated gas in place if geometric effects or asymmetrical drainage for the individual wells is not considered. This study is confined to one of the major Wilcox gas condensate sandstone reservoirs under the Sheridan field, Colorado County, Tex. Production is from 29 irregularly spaced wells located in the central two-thirds of the reservoir. The last one-fourth of the production period under consideration was influenced production period under consideration was influenced by transient drainage effects.

Production acceleration caused a sustained period of transient pressure behavior that resulted in an erratic plot of the ratio of average pressure/gas deviation (P/Z) vs cumulative production. By contrast, the gas material balance curve should be linear for a volumetric reservoir and should not be affected by transient flow if average reservoir pressure can be determined accurately. The pressures used to prepare this performance curve were based on radial flow assumptions and rate weighting techniques.

Similar material balance curves were prepared by estimating the pore volume and area for each well from the linear or semisteady-state portions of pressure-time plots. These data resulted in three pressure-time plots. These data resulted in threeadditional P/Z plots: geometrically corrected; pressure weighted by both Pore volume and production rates; and a pore volume weighted pressure based on radial drainage.

Three indicators were used to measure the effectiveness of the four techniques: the magnitude of the standard deviation; a comparison of the extrapolated and actual initial pressure; and the shape of the performance curve in the anomalous region. The first performance curve in the anomalous region. The first two of these indicators are presented in Table 1 and the third is illustrated graphically in Fig. 1.

It is apparent that volumetrically weighting the individual average well pressures is superior to rate weighting for either method of determining average pressure. This is to be expected since wells draining pressure. This is to be expected since wells draining this reservoir have different rates of pressure decline due to variable extent of formation damage and asymmetrical well drainage geometry. In addition, it is clear that smaller standard deviations result if the effects of asymmetrical (non-radial) drainage are considered.

P. 249
Field Experiment Gathers Friction-Pressure Data for CO2-Energized Fluids
Authors: Tan H. C. , McGowen J. M. , Ridens J. C. , Sandy J. M.
Published: December 2007

A field experiment was conducted on a well with 10,000 ft of 3½-in., 12.9-lbm/ft tubing to gather friction-pressure data for CO2-energized fluids. Seventy-three stages were pumped at various rates, gel concentrations, proppant concentrations, and CO2 qualities to gather sufficient data for modeling and for correlation development. Four side-pocket bundle carriers, with two electronic memory gauges per carrier, were installed at 2,500-ft intervals to monitor pressure and temperature. Four computer data-acquisition systems were used to confirm the integrity of the data collected. The actual friction data that were collected demonstrate the effects of treatment rate, gel concentration, CO2 quality, proppant concentration, and wellbore depth. This information will help researchers better understand the friction-pressure behavior of CO2-energized fluids and should enhance treatment diagnostics, the design of friction-pressure correlations, and existing friction-pressure correlations.
Gas Pricing in Developing Countries: A Case Study of Pakistan
Authors: Sohail H.M. , Abid M.S. , Ansari A.M.
Published: December 2007

Pakistan, a developing country, has gone through various phases of formulating gas pricing policies during its 40-year history of natural gas production and consumption. This paper identifies critical factors that influenced gas pricing policies in Pakistan and adverse effects experienced when any of these factors was not given proper consideration. For instance, on the producer's side, discounted pricing formulas discouraged further exploration and development, leaving high-potential areas unexplored and discovered fields dormant for more than a decade. On the consumer's side, subsidized gas prices encouraged consumption to rise steeply without new discoveries to offset additional surplus consumption. The paper also discusses various short- and long-term variables that should go into a gas pricing policy for developing countries. References to recent policies are also given, indicating how these variables were incorporated in real terms. The conclusions and recommendations, based on Pakistan's long experience with the gas industry, should be useful for other oil-importing countries rich in indigenous gas resources.

Introduction

The development of the gas industry in Pakistan can be traced to 1952, when a large gas discovery was made at Sui. However, the controlled and artificially low gas price initially allowed to producers adversely affected the future of gas exploration and development. This resulted in an energy imbalance, which continued to threaten the economic growth of the industry until recently.

This paper discusses the gas pricing trends during the 40-year history of the natural gas industry in Pakistan. The short-term policy objectives and long-term effects of this pricing policy are also discussed. Using Pakistan as a case study, this paper identifies the major factors that significantly affect the gas pricing framework of a developing country. Though the relative influence of these factors may vary from country to country, their overall importance holds true for all energy-importing developing countries that have indigenous natural gas resources.
Paraffin Deposition from Refined Wax-Solvent Systems
Authors: Patton Charles C. , Casad Burton M.
Published: December 2007

Paraffin deposition from several relined wax-solvent systems was studied by using a coldspot test apparatus The purpose of the investigation was to determine the effect of surface roughness, plastic coatings and solution composition on the plastic coatings and solution composition on the amount of deposition. No correlation was observed between surface roughness and deposit weight. The wax composition determined whether or not a given deposit remained on a given surface. Normal paraffin waxes of lower molecular weight formed paraffin waxes of lower molecular weight formed deposits that sloughed or slid off smooth steel or plastic coated surfaces and flaked off roughened plastic coated surfaces and flaked off roughened steel or plastic coated surfaces. Wax of a higher molecular weight, containing more microcrystalline material, formed deposits that did not slide or flake off either smooth or roughened steel or plastic coated surfaces. Plastic coatings decreased deposit weights by 30 percent or more for the higher molecular weight wax due to thermal insulation. Deposit weight decreased with stirring rate and increased with time and temperature differential.

Introduction

Why paraffin adheres to a surface has long been a point of discussion. Two theories that have evolved are summarized as follows.

WETTABILITY OR FREE SURFACE ENERGY

"As paraffin is deposited on a surface, it is held in place by adsorption forces. These adsorption forces are dependent upon the bee surface energy possessed by both the paraffin and the surface. As possessed by both the paraffin and the surface. As the free surface energy of the plate or surface is reduced, a resultant decrease in the adsorption force holding the paraffin to the plate or surface takes place. This causes a decrease in the amount of paraffin which can be retained on the plate surface for the flow conditions present."

SURFACE ROUGHNESS

"The results obtained in this investigation indicate that wax does not adhere to the pipe wall but is held in place by surface roughness and/or irregularities. As a wax particle grows along the pipe wall and out into the oil stream, the force pipe wall and out into the oil stream, the force tending to move it out of the tubing would increase. The smoother the surface, the more easily the embryonic deposit would be removed from the surface… Thus, it is concluded that wax does not adhere to steel but that deposits which form on steel surfaces are held in place by surface roughness." Or stated more concisely, "Paraffin deposition on metallic or nonparaffinic plastic surfaces at a given temperature is governed by surface roughness." The purpose of this investigation was to determine the effect of surface roughness, plastic coatings and solution composition on paraffin deposition from refined wax-solvent systems. Transparent refined systems were used so that the process could be studied visually. A cold spot test apparatus similar to that used by Hunt and Jorda was used.
Mathematical and Numerical Properties of Control-Volume, Finite-Element Scheme for Reservoir Simulation
Authors: Eymard Robert , Sonier Fernand
Published: December 2007

This paper presents the mathematical properties of a control-volume, finite-element (CVFE) scheme. We show that appropriate constraints on finite-element grids and convenient definitions for volumes and transmissibilities lead to a convergence property for the CVFE scheme. This convergence property proves that use of the CVFE scheme is mathematically correct for reservoir simulation. With the control-volume concept, the local balances of each component are fully satisfied. Because the discretized equations resulting from the scheme can be solved by classic methods, the CVFE scheme can be implemented easily in a general-purpose simulator. In the implementations in this paper, we use prismatic finite elements for 3D full-field simulations and triangles for 2D simulations. The grid is generated with automatic techniques, popular in structural engineering, resulting in numerical diffusion that is as isotropic as possible; therefore, grid-orientation effects are controlled and accuracy is easily improved through natural grid refinement. Examples show that, for the same accuracy, computational costs are lower for results obtained with the CVFE scheme than for those obtained with finite-difference grids. The CVFE scheme is an excellent alternative to flexible gridding techniques used in finite-difference simulators because the entire reservoir can be gridded as required, without use of special techniques for local grid modifications.
Interpretation of Calculated Forces on Sucker Rods
Authors: Lea J. F. , Pattillo P. D. , Studenmund W. R.
Published: December 2007

An examination of the forces acting on a sucker rod string and the relation of those loads to the tendency of a rod string to buckle is presented. Emphasis is placed on the fact that effective, as opposed to true force is the governing parameter for rod buckling. Sample calculations indicate the importance of effective tension in both up-hole rod analysis and near pump rod and sinker bar design.
Application of Artificial Neural Network to Pump Card Diagnosis
Authors: Nazi G.M. , Ashenayi Kaveh , Lea J.F. , Kemp Frank
Published: December 2007

Beam pumping is the most frequently used artificial lift technique. Down hole pump cards are used to evaluate performance of the pumping unit. Pump cards can be generated from surface dynamometer cards using one-dimensional wave equation with viscous damping, as suggested by Gibbs.

Pump cards contain significant information describing the behavior of the pump. However, interpretation of these cards is very tedious and time consuming. Hence, an automated system capable of interpreting these cards is very useful.

This work presents a DOS based computer program capable of correctly classifying pump cards. The program uses a hybrid artificial neural network (ANN) to identify significant features of the pump card.

The hybrid ANN utilizes classical and sinusoidal perceptrons. The network is trained using error back propagation technique.

The program has been able to correctly identify problems in over 100 different training and test pump cards. The ANN requires total of 80 data points as input. Sixty data points are collected from the pump card perimeter itself and the remaining 20 data points represent the slope at selected points on the pump card perimeter.

The problem conditions are grouped into distinct classes such as malfunction anchor tubing, fluid pound, gas interference, and worn traveling valve. The network is capable of identifying one or more of these problem conditions for each pump card. Several examples will be presented and discussed.

Introduction

Sucker-rod pumping system is a very popular means of providing artificial lift for wells. It is estimated that 90 percent of artificially lifted wells use sucker-rod pumping systems.

In order to assure proper operation of these systems it is necessary to monitor them on a regular basis. This is done by means of a dynamometer which is attached to the polished rod of the pumping unit. The plot of load versus position generated by the dynamometer is known as a surface card.

Using the technique proposed by Gibbs this surface card can be used to obtain down hole "pump card". The pump card presents the load versus position at the pump down hole instead of the load versus position at the polished rod on the surface.

The shape of the pump card can be used as a diagnosis tool. For example, when the pump is functioning properly and pumping to its full capacity the pump card will have a rectangular shape. When the pump capacity is not being fully utilized then we may have a condition called "fluid pound".

The petroleum industry is in the process of automating the control of pumping wells. Computers are being used to continuously monitor the pump and transmit data to a central office for further analysis. The shear volume of data received makes it necessary to develop tools for automatic analysis of the pump cards.

Various pattern recognition techniques have been used to analyze the down hole pump card. Traditional techniques require significant processing time.

P. 151^
A Theory Relating High Temperatures and Overpressures
Authors: Lewis C.R. , Rose S.C.
Published: December 2007

The theory proposed here is that an overpressured zone, because it is uncompacted, constitutes a thermal barrier. That is, this uncompacted zone contains excess amounts of water, and water has three times the insulating value of the rock matrix. It follows that the greater the water content, the greater the insulating value of the zone.

Introduction

For any drilling area, geothermal gradient maps have been made that attempt to show the "normal" temperature gradients that will be found. Along the Texas Gulf Coast these will range from 1.6 degrees to 2.2 degrees F/100 ft. Most of the time the temperature profile for a new well can be predicted from one of these maps. At times, however, we find that the temperature gradient changes with depth. Other authors have observed that in the Gulf Coast region the overpressured zones also have abnormal temperature gradients. The fact that abnormally high gradients seem always to occur with overpressured zones is both significant and unexplained. We advance a theory to relate high pressure zones and deviations from normal temperature profiles. profiles. The Theory

It is generally agreed that almost all of the heat flowing within the earth comes from the core and moves outward to the surface where it is lost into space as radiant energy. Wherever flowing heat meets an obstacle (an insulator) there is a buildup of heat against its face. The temperature rises on this face until a higher temperature gradient exists across the obstacle. Enough heat will then flow through the insulator to balance the flow of incoming heat. It is clear that a higher temperature gradient must be imposed across a heat insulator than across a heat conductor to achieve equal heat-flow rates. Therefore, if we observe a very high gradient within the earth, we would normally conclude that the high gradient zone is an insulator. Our theory is that high pressure zones are heat insulators; therefore, we expect abnormal temperature gradients to exist across them. An analytical proof follows. proof follows. We must show that a high-pressure zone is in fact an insulator. A high-pressure zone differs structurally from the surrounding rock in that it is less compacted. There is much more pore space to be occupied by fluid. Thus, an overpressured, uncompacted rock has considerably more water than a normally pressured, compacted rock. The conduction of heat is expressed by

where is the heat flow, kh is the coefficient of thermal conductivity of the substance, A is the cross-sectional area of the substance, measured perpendicular to the flow of beat, delta T is the perpendicular to the flow of beat, delta T is the temperature change across the substance, and L is the length (thickness) of the substance. It can be seen that varies directly with kh. Thus, if water has a lower value of kh than silica, water is the better insulator.

JPT

P. 11
Casing Design for Trapped Annular Pressure Buildup
Authors: Halal A. S. , Mitchell R. F.
Published: December 2007

Conventional single-string analysis for casing design with annular-fluid expansion can underpredict or overpredict pressures between strings because multistring effects are neglected. Multiple-string systems with multiple sealed annuii behave as composite interactive systems. This paper presents a constitutive-based multistring analysis method for composite string effects and complex fluid behavior. The composite stiffness of cemented casings is determined from elastic stress/strain relationships, and the nonlinear fluid behavior is modeled by direct use of fluid PVT relations in the formulation and solution. The method is incorporated in a computer model linking comprehensive stress calculations to accurate temperature and pressure predictions. Sensitivity studies of the system response to various key parameters and operating conditions are presented, and comparisons are made with single-string analyses to demonstrate the strong interaction between casing strings.
Disposal of Oily Cuttings by Downhole Periodic Fracturing Injections, Valhall, North Sea: Case Study and Modeling Concepts
Authors: Moschovidis Z. A. , Gardner D. C. , Sund G. V. , Veatch R. W.
Published: December 2007

This paper presents the results of a pilot study for the injection of cuttings at great depth [8,094 ft total vertical depth (TVD)] in Paleocene/Eocene shale by periodic fracturing injections in two wells in the Valhall field in the North Sea. Injection is necessary to meet environmental requirements (< 1 vol% of oil in the cuttings disposed in the sea) that went into effect Jan. 1,1993. Valhall is an Upper Cretaceous chalk oil reservoir ≈ 180 miles offshore southern Norway. Amoco operates the field for Amerada Hess Norge A/S, Elf Petroleum Norge A/S, and Enterprise Oil Norge Ltd. Simulations were performed with a new conceptual model for disposal of cuttings (called the "disposal domain"). The actual pressure response during cuttings injections supports the model predictions. The cuttings are contained within a limited region of the formation (the disposal domain) where a system of hydraulic fractures have been created. The same model then was used to estimate the capacity of the formation to contain cuttings without increasing the treating pressure (and the closure stress) beyond the capacity of the tubulars.
Heated Mud Systems: A Solution to Squeezing-Salt Problems
Authors: Muecke N. B.
Published: December 2007

Squeezing salts have been a major problem to operating companies worldwide for many years. Most previous solutions to the problem have been aimed at treating the symptoms rather than the cause. Generally, these have been based on running casings capable of withstanding the nonuniform salt loadings because satisfactory cementations have been virtually impossible to achieve because of large washouts in the salt layers. The solution is to use standard oilfield equipment to drill a gauge hole through the squeezing salts, thus providing an optimum cementation environment. Various methods were used to try to resolve the problem; the last was the use of thick-walled casings in conjunction with saturated potassium/ magnesium drilling fluids to reduce salt washout. Unfortunately, washouts still occurred because the muds could not be saturated at the surface to downhole conditions. Now, the drilling fluid is heated on the surface, enabling the required level of salt concentration to be achieved. The heating system, comprising a boiler and heat ex-changer from a conventional well-test package, has been used on eight wells to date. In each case, a gauge hole was drilled through the squeezing-salt sections and, subsequently, successful cementations were performed.
Gas-Well Deliverability Monitoring: Case Histories
Authors: Thrasher T. S.
Published: December 2007

This paper presents practical techniques that can be used to monitor gas-well performance. These techniques, along with the routine examination of performance data, can help the engineer maintain production potential and extend well life. This paper demonstrates the importance of monitoring well performance on a regular basis through case history examples. Four types of well conditions are described: (1) deterioration in performance over time, (2) drainage area change, (3) liquid loading, and (4) tubing design constraint. This paper also discusses the use of a personal computer program as a tool to facilitate and encourage gas-well performance monitoring.
Using PC's and Monte Carlo Simulation To Assess Risk in Workover Evaluations
Authors: Wiggins Michael L. , Zhang Xu
Published: December 2007

Implementing Monte Carlo methods on a PC can significantly improve risk assessment in the evaluation of workover opportunities. Monte Carlo simulation is a probabilistic method that allows the evaluator to consider an entire range of potential outcomes. This paper presents a method for implementing Monte Carlo methods in a PC environment to evaluate workover opportunities.
Parameterization of Complex 3D Heterogeneities: A New CAD Approach
Authors: Wietzerbin L. J. , Mallet J. L.
Published: December 2007

This paper presents a new method for generating and interpolating complex reservoir shapes in 3D. The method combines integration of quantitative knowledge about the shapes of the geologic bodies being modeled and generation of a large range of possible geometries corresponding to this knowledge. It is a new CAD approach based on the discrete smooth interpolation method (DSI). We apply this method to the geometric modeling of part of a complex turbiditic reservoir. In this example, channels and lobes account for most of the production, and their geometries are critical factors for oil recovery. Data include well logs, statistics about the shapes of main reservoir heterogeneities, and 3D templates representing the most likely shape. Geometric characterization of the sand bodies in this field is performed through stochastic modeling. The method used involves a Boolean approach based on indicator components and emphasizes the importance of honoring well data.
Gas/Oil Capillary Pressure of Chalk at Elevated Pressures
Authors: Christoffersen K. R. , Whitson C. H.
Published: December 2007

Accurate capillary pressure curves are essential for studying the recovery of oil by gas injection in naturally fractured chalk reservoirs. A simple and fast method to determine high-pressure drainage capillary pressure curves has been developed. The effect of gas/oil interfacial tension (IFT) on the capillary pressure of chalk cores has been determined for a methane/n-pentane system.

Measurements on a 5-md outcrop chalk core were made at pressures of 70, 105, and 130 bar, with corresponding IFT's of 6.3, 3.2, and 1.5 mN/m. The results were both accurate and reproducible. The measured capillary pressure curves were not a linear function of IFT when compared with low-pressure centrifuge data. Measured capillary pressures were considerably lower than IFT-scaled centrifuge data. It appears that the deviation starts at an ΓFT of about 5 mN/m.

According to the results of this study, the recovery of oil by gravity drainage in naturally fractured chalk reservoirs may be significantly underestimated if standard laboratory capillary pressure curves are scaled by EFT only. However, general conclusions cannot be made on the basis of only this series of experiments on one chalk core.
Permanent Downhole Gauges Used in Reservoir Management of Complex North Sea Oil Fields
Authors: Unneland Trond , Haugland Torstein
Published: December 2007

This paper presents experience with and applications of permanent downhole pressure and temperature gauges in the reservoir management of two complex North Sea oil fields, Gullfaks and Veslefrikk (both operated by Statoil A/S). In total, 40 quartz and quartz capacitance gauges from three different suppliers have been installed in platform wells over 6 years. The gauges have given invaluable realtime data for reservoir management of these two fields and contribute directly to increased daily oil production. The installations have proved to be safe and reliable, as well as good investments.
Real-Time Pore Pressure and Fracture-Pressure Determination in All Sedimentary Lithologies
Authors: Holbrook P. W. , Maggiori D. A. , Hensley Rodney
Published: December 2007

Pore pressure and fracture gradient are the two natural limits that exert the greatest influence on drilling costs and safety. Traditional empirical "pore pressure" models are limited to one lithology type (shale) and rely on incorporating petrophysical or drilling data vs. depth trend lines. We describe a new method that quantifies the effective-stress law, p = S − σv. This method uses petrophysical data (gamma ray, resistivity, density) and mineralogic stress/strain relationships to calculate pore pressure and fracture gradient, on a foot-by-foot basis, through all sedimentary rock types.

Cretaceous marls and limestones have proven to be an obstacle for traditional pore-pressure evaluation methods. With numbers of high-pressure exploration wells in the North Sea Central graben increasing, there is a need for a better understanding of pressures through the Cretaceous and into the pressured formations below. This effective-stress-law method, which is used to determine pore pressure/fracture gradient, has been tested successfully in the complex limestone/shale and sandstone-shale sequences of the North Sea as an aid to well planning and real-time drilling operations decision making by use of measurement while drilling (MWD) petrophysical data.

This method has recently been used successfully on two Central graben wells. BP drilled a high pressure/high temperature (HPHT) well in the second quarter of 1993 and used on-site pore pressure and fracture gradient (PP/FG) calculations, along with other more traditional pore-pressure methods, to help set an intermediate casing string at an optimum depth. We discuss results of these case studies and technical content of this pore-pressure method.
Pressure Transient Analysis of Dually Fractured Reservoirs
Authors: Al-Ghamdi Abdullah , Ershaghi Iraj
Published: December 2007

Dual fracture models are examined as a more realistic alternative to dual porosity models for the representation of naturally fractured reservoirs. A major component of the fracture system is the network of microfracture which by virtue of their lower permeability respond somewhat later than the macrofractures. A delineation of microfracture response versus matrix response is made using the proposed conceptual models. It is demonstrated that the microfractures response may at times be mistakenly attributed to matrix.
A Simplified Analysis of Unsteady Radial Gas Flow
Authors: Aronofsky J.S. , Jenkins R.
Published: December 2007

A simple means of predicting the flowing well pressure history in a natural gas reservoir has been developed. The differential equation for unsteady radial flow of gases through porous media was solved by numerical methods using electronic punch card machines. The results obtained from these calculations are presented in a generalized form which is believed to be most convenient for engineering use. These results are compared with those presented in a paper by Bruce, et al.

An effective radius of drainage has been defined which permits the equation of steady state gas flow to be used easily to predict well pressures in gas reservoir depletion. An equivalent effective radius of drainage is defined for liquid flow systems and a comparison is made of the gas solution to the liquid solutions.

Introduction

This paper presents a numerical method for describing the transient flow of gases radially through a porous medium from which the production rate is specified. The results obtained from these calculations are presented in a generalized form which is believed to be the most convenient for engineering use.

The principal application of these calculations should be to flow in natural gas reservoirs, in the interpretation of pressure drawdown tests, in the estimation of reserves, and in calculation of injection pressures required in gas injection and cycling operations. The evaluation of natural gas wells is based upon back-pressure tests in which measurements of production rate and flowing well pressure are made for periods of one, two, or more days. The flow is assumed to have stabilized at this time, and the observed values of pressure and production rate are used with standardized formulae to determine the well's allowable production rate. Furthermore, the results obtained from such a test of short time duration are extrapolated in such a manner to allow a prediction of what the well pressure will be at some future time for a specified (but possibly untested) flow rate.
Effects of P-p-T Behaviour of Muds on Static Pressures during Deep Well Drilling - Part 2: Static Pressures During Deep Well Drilling
Authors: Babu D. R.
Published: December 2007

In this study, published p-ρ-T data of twelve muds are compared using three models already proposed. The empirical model suggested by Kutasov is found to represent the measured data more accurately than the other models for a majority of the muds. With the help of the empirical model, an explicit equation is derived analytically to predict static pressures at different depths. Based on the analysis, an equivalent static density (ESD) variable is defined that incorporates the mud p-ρ-T behavior, pressure and temperature of the mud at surface, thermal gradient, and depth of the well. It is suggested that ESD should be used in place of normally used mud weight term in all phases of deep well drilling. The analysis is applied to a high-temperature, 25,000-ft deep example well. It is observed that static pressure or ESD at the bottom of the well decreases during tripping and the extent of decrease is dependent on the type of mud. For the example well, it is estimated that a maximum reduction in ESD of about 0.62 lbm/gal occurs in the case of 18-lbm/gal water-basedmud, and a minimum reduction of about 0.2 lbm/gal occurs in the case of a 11-lbm/gal diesel-oil-based mud.
Examples of Petroleum Engineering Objects
Authors: Griffiths A. E.
Published: December 2007

In recent years, object-oriented (OO) methods have gained prominence among software developers as a means of more closely modeling the real world.1,R2 Most OO applications to date have their roots in the field of computer science, and this may deter people without a strong computing background from further investigating OO. However, OO methods can be applied to concepts that may be more familiar to petroleum engineers. The intention of this paper is to demonstrate that the power of OO can be used to simplify the solution of practical problems by engineers having only a limited background in computing. We present three such petroleum engineering applications in this paper: probabilistic reserves evaluation, a gas recycling scheme, and material-balance calculations.

In the first of these examples, we use OO methods to model a simple gas recycling scheme, taking into account explicitly vapor/liquid equilibrium, both in the surface separation train and in the reservoir. In the second example, we use OO methods instead of the well-known Monte Carlo method to derive a reserves expectation curve. In the third example, we analyze the Schilthuis material-balance method and represent it using simple objects.

A brief introduction to objects will prepare the ground for the more detailed analysis of these applications. In each case, we briefly review the underlying principles and analyze them in terms of objects. We will demonstrate the structure and implementation of each of the resulting object classes using short C++ programs.3 Finally, we apply these object classes to the solution of some real-life problems that have appeared in the petroleum engineering literature.
Ensemble Computing for the Petroleum Industry
Authors: Annaratone Marco , Dossa Don
Published: December 2007

"Computer downsizing" is one of the most often used buzzwords in today's competitive business, and the petroleum industry is at the forefront of this revolution. Ensemble computing provides the key for computer downsizing with its first incarnation, i.e., workstation farms. This paper concerns the importance of increasing the productivity cycle and not just the execution time of a job. We introduce the concept of ensemble computing and workstation farms. Then we discuss how different computing paradigms can be addressed by workstation farms.
An Analysis of Horizontal Wells Intercepted by Multiple Fractures
Authors: Raghavan Rajagopal S. , Chen Chih-Cheng , Agarwal Bijan
Published: December 2007

A mathematical model is developed and used to discern the characteristic responses of a multiply-fractured horizontal-well. A systematic discussion of pressure behaviors is given. New interpretations and conclusions are provided. A simple, screening guide to evaluate the efficacy of this completion scheme is presented. The consequences of perforating selective sections after fracturing are examined. The pressure behaviors that are discussed in this work are used to analyze responses of a field test. This test was conducted on a medium-radius horizontal-well completed in a dolomite/anhydrite formation with a 1900′ horizontal section. Four distinct intervals were perforated and individually stimulated. Results from the analysis of the commingled test are presented in this work. The methodology outlined here should be useful to others. Practical guidelines are provided.
Gel Placement in Fractured Systems
Authors: Seright R. S.
Published: December 2007

This paper examines several factors that can have an important effect on gel placement in fractured systems, including gelant viscosity, degree of gelation, and gravity. For an effective gel treatment, the conductivity of the fracture must be reduced and a viable flow path must remain open between the wellbore and mobile oil in the reservoir. During placement, the gelant that "leaks off" from the fracture into the rock plays an important role in determining how well a gel treatment will reduce channeling. For a given volume of gelant injected, the distance of gelant leakoff is greater for a viscous gelant than for a low-viscosity gelant (other factors being equal).

In one method to minimize gelant leakoff, sufficient gelation is designed to occur before the gelant leaves the wellbore. We investigated this approach in numerous experiments with both fractured and unfractured cores. We studied Cr(III)/acetate/hydrolyzed polyacrylamide (HPAM), resorcinol/formaldehyde, Cr(III)/xanthan, aluminum/citrate/HPAM, and other gelants and gels with various delay times between gelant preparation and injection. Our results suggest both hope and caution concerning the injection of gels (rather than gelants) into fractured systems. Tracer studies indicate that some gels can effectively heal fractures under the right circumstances. However, high resistance factors exhibited during placement could limit the ability to propagate certain gels deep into a fractured system unless the fractures are very conductive.
Modeling the Effects of Infill Drilling and Pattern Modification in Discontinuous Reservoirs
Authors: Christman P. G.
Published: December 2007

This paper present a lens model, based on a physical concept of the individual pay members, that is the first model designed to calculate reserves from infill drilling and pattern changes. The model conceptualizes the reservoir as being made up of a large number of randomly located circular disks or lenses sealed at the edge. Calculations of drainability, floodability and secondary/primary ratio are presented for two calibrated lens-size distributions. The results of these calculations are compared with the performance of some Wasson Clearfork trend waterfloods.
A Mechanistic Model for Circulating Fluid Temperature
Authors: Hasan A. R. , Kabir C. S. , Ameen M. M. , Wang Xiaowei
Published: December 2007

An accurate fluid temperature profile in both tubing and annulus during circulation is desirable to allow computation of circulation rates. However, because the circulating fluid exchanges heat with the formation, fluid temperature changes both with time and depth. Consequently, the fluid's intrinsic properties of density and viscosity would change with an increase in circulation time, thereby influencing the optimal pumping rate.

Existing analytic methods for solving the heat transfer problem at hand generally assume a constant fluid inlet temperature plus a constant heat flux (or temperature) at the wellbore/ formation interface. These assumptions ignore the reality that the temperature of the circulating fluid entering the wellbore from the holding tank increases with time because of the heat carried by this fluid from the hot formation. Fluid circulation also causes a gradual decrease in heat flux between the wellbore and the formation. These assumptions inherent in the available methods may reduce their reliability in many situations.

In this work, we present a generalized analytical model for circulating fluid temperature in both conduits, for both forward and reverse circulation cases, as a function of circulation time and well depth. We use an energy balance for the fluid in the tank to express its temperature as a function of time. To account for the changing heat flux at the wellbore/formation interface, the principle of superposition in time is used. The heat flux schedule is represented by adding constant heat sources at successive times. This model is flexible to adapt any transient temperature distribution model, TD, and presupposes unsteady heat transport in the formation while steady heat flow occurs in the tubular.

Our results show that, under some circumstances, thud temperatures estimated using these approaches deviate significantly from that estimated without account for the varying nature of tank temperature or formation heat flux This difference is especially true when the temperature difference between the bottomhole and the wellhead is large. Thus, varying mud tank temperature and formation heat flux need to be accounted for when estimating flowing fluid or circulating mud temperature in the Arctic. However, when the bottomhole and wellhead temperature difference is small, the extra computation involved in this procedure is probably not worth the marginal gain in accuracy. Field examples illustrate the model's application.
On Estimating Recovery Efficiency in Depletion Drive and Water Drive Reservoirs
Authors: Sandrea Rafael
Published: December 2007

Recently the API Subcommittee on Recovery Efficiency published a comprehensive statistical study of recovery processes, based on the actual performance of some 150 reservoirs located throughout the U. S., Canada and the Middle East.' Eighty of these reservoirs had only a depletion drive mechanism and the other 70 reservoirs had active water drives. Moreover, all of the water drive and 84 percent of the gas drive reservoirs were produced from sandstone formations, whereas 16 percent of the gas drive samples were produced from carbonate rocks. In the API study, which in effect is an extension of the well known investigations of Craze and Buckley and Guthrie and Greenberger regression equations were developed for each of the two mechanisms mentioned above, relating the recovery efficiency, RE, to several physical parameters that describe some of the oil and formation characteristics.

For Depletion Drive Reservoirs (sands, sandstones, and carbonate rocks):

................(1)

For Water Drive Reservoirs (sands and sandstones):

..............(2)

The standard errors of estimate of Eqs. 1 and 2 are 22.9 and 17.6 percent, respectively. To simplify the solution of these equations, the following nomographs were prepared. Note that recovery efficiency is expressed as a percent of the oil in place at the original pressure for the water drive reservoirs, and at the bubble-point pressure for the gas drive cases. Equivalent values for the recovery factor in barrels per acre-foot of net pay may be obtained by multiplying the values of recovery efficiency

by 71.58 times the oil-in-place term

(use Boh for depletion reservoirs and Boi for water drive reservoirs). For details on the valid range of values of the individual parameters that appear in Eqs. 1 and 2, the original study' should be consulted. However, the nomographic scales essentially represent the range of the data used in their correlation.

Nomenclature

B = oil formation volume factork = absolute permeability, darciesp = reservoir pressure RE = recovery efficiency, percent S = saturation, fractionu = viscosity, cp = porosity, fraction

P. 277
An Iterative Matrix Solution Method Suitable for Anisotropic Problems
Authors: Watts J.W.
Published: December 2007

Often, the most time-consuming step in solving partial differential equations in two space partial differential equations in two space dimensions is an iterative solution of the finite-difference equations. For the closed boundary case, this solution is difficult when the equations are anisotropic, as they are normally when mesh spacing is much longer in one direction than in the other. This paper presents a solution method for use in such problems. The method is shown to be very fast in an anisotropic problem, but not as fast as other available methods in an isotropic problem. the extension to three space dimensions is outlined.

Introduction

In the finite-difference solution of multidimensional parabolic or elliptic equations, a set of many linear parabolic or elliptic equations, a set of many linear simultaneous algebraic equations arises. The most time-consuming part of the solution is the solving of this set of equations, normally accomplished by using some iterative method. Often the finite-difference equations are anisotropic. By anisotropic it is meant that two of the of diagonal coefficients in each equation are much larger than the other off-diagonal coefficients. When this occurs, the solution becomes more difficult for the closed boundary case. Until recently it appeared that line successive overrelaxation was the best technique to use in such a situation. Now, a method developed by Stone appears best among those published. This paper describes an alternative method for use with anisotropic systems. The method can be considered to be a specialization of a more general technique discussed by De la Vallee Poussin. It consists of a correction applied at each mesh point in a line, coupled with line successive overrelaxation. The method is shown to be very fast in a two-dimensional anisotropic problem. The extension to three dimensions is outlined, but no calculations are presented for that case. A theoretical analysis of the new method will be the subject of a later paper. paper.

METHOD

Consider the physical system from which the finite-difference equations are derived, as shown in Fig. 1. The system is represented by a matrix of mesh points. The finite-difference equation at each mesh point takes the form

.........(1)

All coefficients with the exception of di, j, are nonnegative. If the problem is elliptic (steady-slate), bi, j is zero. This equation is more commonly written as follows.

.....(2)

where

This equation is written for each mesh point to create the set of simultaneous algebraic equations that must be solved. The matrix formed from the coefficients of these equations is often symmetric. The mesh points in Fig. 1 are arranged in a square pattern.

SPEJ

P. 47
Experimental Compaction and Evolution of Physical Properties of Clay-Sediments
Authors: Djéran-Maigre Irini , Grunberger Daniel , Rousset Gilles
Published: December 2007

For a better understanding of sedimentary basin development, we studied the evolution of kaolinite with compaction. We made experimental compaction tests in a specially designed oedometric cell. We then characterized the obtained samples microscopically and macroscopically and made correlation between those parameters.