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Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-86

... computers at the receiving end. Expert systems and application software are used to analyze technical data for reservoir modeling, geological and geophysical analysis and

**interpretation**, land price analysis, and history-based forecasting for economics and planning. The problems facing management in the...
Abstract

Abstract The advent of true client/server technology, high speed personal computers and global access through the internet is causing the two worlds of the business process and the computer to collide as management demands better information to use in decision-making. This paper will focus on the concept of organizing the business process to fit the goals and objectives of the enterprise, then tailoring the use of computers and software to the people, processes and data in a coherent fashion, enabling management to "see" the business more completely and therefore manage it more effectively. Computer systems are used to store and process enormous amounts of data for various parts of a business; accounting, land, reserves, documents, geotechnical and so on. Reports containing portions of this data are generated for both internal and external purposes and are often stored and processed by computers at the receiving end. Expert systems and application software are used to analyze technical data for reservoir modeling, geological and geophysical analysis and interpretation, land price analysis, and history-based forecasting for economics and planning. The problems facing management in the mineral resource industry relate to the many facets of managing risk in a volatile environment. They must be able to grasp and manipulate complex essential information to ensure the best use of their people, capital and opportunities within the business process they have adopted to achieve their goals and objectives. They want business process related information that tells them about their own operation and their marketplace. They need reporting methods that tell them about their return on assets, capital, business units and specific properties. They need to know how they compare to their competition and how the investment community perceives them. People planning, blueprinting and executing the business process to achieve corporate objectives is at the heart of commerce. The use of computers must facilitate the business process without interfering with, or attempting to replace it. Client/server, internet, multimedia technology offer the means to enhance the business process, but only through first defining and understanding the process, then choosing and implementing the most effective combination of computers and software to enable the business process to succeed. Introduction The situation in today's mineral resources industry is one of tremendous growth and change. New players appear daily, old players consolidate, mergers and acquisitions create new superstars and they all need information that is current, relevant and easily digested to stay in the game. The data that forms the basis for this information is captured, stored and managed by different parts of each organization for their specific functional needs and for purposes of reporting to management on their activities. Once the data is put into context it becomes "information". Our industry generates such large volumes of data it has spurred the development of electronic means to store and process the data so that it may become information. "Computerization" of the industry began long ago with the development of accounting systems and geophysical systems.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-45

... Abstract This paper presents an integrated approach to data

**interpretation**during pool or field development. The methodology is based on the integration of data at different levels of resolution, multivariate statistical analysis, and advanced computer graphics. Statistical techniques...
Abstract

Abstract This paper presents an integrated approach to data interpretation during pool or field development. The methodology is based on the integration of data at different levels of resolution, multivariate statistical analysis, and advanced computer graphics. Statistical techniques compress and organize large amounts of data into a small set of information. They aid in the identification of the most significant factors, any valid relationships, and patterns hidden in geological databases. Statistical processing estimates the degree of uncertainty surrounding exploration events, while visualization techniques provide a presentation and interpretation tool. Special attention has been given to the application of scientific visualization for presenting and analyzing multidimensional data sets. The paper explains how to convert multidimensional geological data sets into a single parameter defined as the production probability. This parameter is visualized together with the three-dimensional properties of the formation. In addition, the paper presents a method for overlaying different multivariate data sets representing non-overlapping sparse matrices. The techniques presented in this paper improve the testing of geological hypotheses and lead to advances in the understanding of "cause and effect" relationships between formation properties, field activities, and well performance. Introduction The methods and techniques described in this paper are useful in identifying any valid relationships and patterns hidden in exploration and development databases. In general, geological data is multidimensional, often noisy, non-reproducible and worst of all, the majority of geological samples are mixtures of simpler components. Statistical and numerical methods can help to un-mix these samples, find the original compositions of sample data, find variance and patterns, and define and test geological hypotheses 1 . These techniques help to summarize the multivariate data and relate it to geological events. In addition, they help to identify the most important factors, which are then used to develop the predictive models. These models can be quantified, and used to direct exploration and development efforts in areas with the highest possible potential. Computer graphics and specifically, scientific visualization, improve the interpretation process of the data or results of the statistical analysis 2,3,4 . Statistical analysis and scientific visualization were applied to estimate the production capacity or production probability based on available geological, petrophysical, and engineering data in a naturally fractured reservoir. Results of the analysis were used to provide answers and build hypotheses in the exploration process. Statistical models allowed for the selection of regions of interest or specific sites (wells) with a higher potential than the surrounding locations. The following is a list of steps in the analysis: development of the integrated data base univariate analysis with the necessary data checks estimation of pair wise correlations estimation of correlations between groups (canonical correlations) development of mathematical models to predict production rates development of models which discriminated between good and poor performers visualization of data and models. The next section presents the most important steps of the analysis. DATA ANALYSIS Data Base The project data base contained geological, petrophysical, DST, and completion parameters. The geological and petr

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 9–11, 1996

Paper Number: PETSOC-96-41

...

**interpretation**of counter-current imbibitions experiments on reservoir core samples. Usually imbibitions tests are conducted to obtain qualitative estimates of reservoir wettability and oil recovery. This paper presents a procedure for history matching of counter-current imbibitions tests that involves...
Abstract

Abstract Currently available spreadsheet software packages offer an easy to implement and user friendly platform for setting up problems involving nonlinear parameter optimization. This paper presents the application of one such software "Solver" embedded in MS-Excel for quantitative interpretation of counter-current imbibitions experiments on reservoir core samples. Usually imbibitions tests are conducted to obtain qualitative estimates of reservoir wettability and oil recovery. This paper presents a procedure for history matching of counter-current imbibitions tests that involves minimization of a user-defined global objective function with respect to various model parameters. Application of this procedure for many counter-current imbibitions experiments reveals that a single dimensionless function can represent imbibitions recovery history for most rock samples. Also, apparent contact angles for various samples are consistent with their expected wettability. The parameter optimization procedure presented in this paper offers a powerful and efficient method that can be modified to solve numerous reservoir and production engineering problems. INTRODUCTION Solution of many common problems encountered in different facets of oil & gas industry requires obtaining values for parameters embedded in highly non-linear mathematical models. Examples of such problems include: determination of petro physical properties, skin, and drainage radius of a reservoir based on pressure transient data and/or production decline data 1 ; forward modeling for obtaining petro physical properties of vertical sequences by matching response of a suite of wire-line logs; and interpretation of laboratory core floods for determining relative permeability curves 2,3 . Solution procedure for these and other similar problems usually requires assignment of initial guesses for the unknown parameters, predicting system response using the available model, and using the quality of match between the actual and predicted system response to correct the value of parameters. Such procedure is continued until a satisfactory agreement between system response and model predictions is obtained. For many problems, such strategy is easier to implement than attempting to explicitly obtain various parameters because of the non-linear nature of mathematical formulation obtained in the model. Approaches suggested in the past for implementing such parameter determination include kriging 1 , simulated Annealing 2,3 , regression 4 , and optimal control theory 5 . Implementation of any of these parameter determination procedures requires extensive amount of programming effort or investment in some expensive software which may need to be customized in order to operate compatibly with user developed code. Commercially available spreadsheet software packages offer built-in utility software for determining parameters of a non-linear formulation. This paper describes the implementation of a non-linear model on the spreadsheet software MS-EXCEL. The parameters of this model were refined using the built-in utility "SOLVER" by seeking to minimize a user-defined objective function. Experiments involving imbibitions of water andproduction of oil are commonly conducted on the core samples from fractured reservoirs in order to characterize mass-transfer of oil from the matrix to the fracture system 4 . Such tests are also conducted to understand the wettability of reservoir rocks. Gupta and Civan 6 developed a three exponent transfer function based on mathematical analysis to represent the cumulative production of oil during th

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 9–11, 1996

Paper Number: PETSOC-96-51

... are usually evaluated at the initial pressure level. Comparison of the analytical solutions with numerical solutions obtained for a variety of typical well test conditions indicates the magnitude of inaccuracy incurred by using standard approach to data

**interpretation**. Based on this investigation...
Abstract

Abstract The fluid flows in porous medium is described by the diffusion type of partial differential equation. In deriving the flow equation for the constant compressibility fluids, an important assumption is made regarding the magnitude of the pressure gradient: it is assumed that this gradient is small enough that the square of this term becomes negligible. In this study, an attempt is made to quantify the effect of this simplification. Data generated by numerical simulator and analytical solutions are compared in order to determine the conditions under which this simplification is justified. The drawdown solution on gas wells contains gas properties, which are pressure dependent. As the system is being depleted, the average reservoir pressure declines. Although it seems logical to consider the gas properties at the prevailing reservoir pressure, the gas viscosity and compressibility are usually evaluated at the initial pressure level. Comparison of the analytical solutions with numerical solutions obtained for a variety of typical well test conditions indicates the magnitude of inaccuracy incurred by using standard approach to data interpretation. Based on this investigation, several pressure levels for properties calculation are considered. INTRODUCTION Well test analysis is based on expressions obtained by solving the flow (diffusion) equation for a variety of boundary conditions. The flow equation which represents the core of the pressure transient method is based on the principle of mass conservation, Darcy's law, and an appropriate constitutive assumption: the constant compressibility concept for liquids, and the equation of state for real gases. The general form of the flow equation contains a nonlinear term, the square of the pressure gradient. Obviously, the occurrence of this non-linearity IS mathematically inconvenient and thus should be eliminated if possible. The simplification is achieved by assuming small pressure gradients in the formation; consequently, a square of a small number can be ignored. To the best of our knowledge, no study has been reported which would determine whether or not such a simplification is indeed justified. In this study, the effect of a non-linear term on the interpretation of transient data was evaluated by comparing the analytical solutions with numerical solutions which are generated for the identical test conditions. For gas reservoirs, a step-wise approach and a pressure averaging method for evaluating the gas properties in analytical solutions are proposed. The one dimensional flow of a slightly compressible fluid (oil) in porous medium can be expressed, in a dimensionless form, as follows: Equation(1) (available in full paper) where non-linear coefficient N c is defined as Equation(2) (available in full paper) and dimensionless pressure P D Equation(3) (available in full paper) Due to the pressure dependence of gas properties, the diffusion equation for gas flow is usually liberalized by using a pseudo-pressure [1] . The dimensionless form of the partial differential equation for gas flow is expressed as Equation(4) (available in full paper) and the pseudo-pressure is defined as Equation(5) (available in full paper) The dimensionless pressure then becomes Equation(6) (available in full paper) Where Equation(7) (available in full paper) Equation(8) (available in full paper) The numerical simulator is based on equations (I) and (4). The solutions are obtained for the condition of a constant production rate, the early transient and the pseudo-steady state time periods.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 9–11, 1996

Paper Number: PETSOC-96-53

... matching techniques of pressure and pressure derivative to determine several reservoir parameters are presented. Then, a new techniques, known as direct synthesis, for

**interpreting**the pressure behavior of a horizontal well without type-curve matching is presented. Characteristic points are obtained at...
Abstract

Abstract The horizontal well is treated as a partial penetrated vertical well in closed rectangular reservoir. Thus, the performance of horizontal well is determined from equations normally applicable to vertical wells. This study proposed the new equation for the first radial flow. Type curve matching techniques of pressure and pressure derivative to determine several reservoir parameters are presented. Then, a new techniques, known as direct synthesis, for interpreting the pressure behavior of a horizontal well without type-curve matching is presented. Characteristic points are obtained at intersections of various straight line portions of the pressure and pressure derivative curves, slopes and starting times of these straight lines. These points, slopes and times are then used with appropriate equations to solve directly for reservoir characteristics. A step-by-step procedure for calculating these parameters without type curve matching is included in this paper. The productivity index equation is derived from the conventional pseudo steady state equation for a vertical well in a bounded reservoir. INTRODUCTION One of the most active areas in petroleum industry is horizontal well technology development. Experts 1 predict that the number of horizontal wells will rise considerably in the next century and this technology will be applied increasingly to initial reservoir development. However, the cost of drilling a horizontal well is much higher than that of a vertical well. Therefore, interpretation of well-test data and prediction of a horizontal well performance is more critical. Testing horizontal well 2 is still challenging in terms of measurements and interpretation. The field experience documented in the last decade indicates that interpreting tests for horizontal wells is much more difficult that for vertical wells. Several mathematical models 3–8 have been proposed in the literature. The available well testing and interpretive methods for a horizontal well are much more complex than the ones for a vertical well due to wellbore storage effect boundary effects and partially penetration. There is no unique type cure for analyzing pressure transient tests of horizontal wells because (a) more than one flow regime may occur. (b) different flow regime require different techniques and different types of plots. In order to interpret well test data using existing techniques, more understanding of the characteristics and durations of each flow regime is needed. Alternatively, a more sophisticated and easier method is proposed for interpreting horizontal well pressure data. The objectives of this paper are to present a new mathematical model for a horizontal well in a bounded system to present the new set of type curves of pressure and pressure derivative response at the well bore, to develop new well techniques for analyzing pressure tests with and without type-curve matching techniques and to present a new equation of horizontal well productivity MODEL DEVELOPMENT Physical Model This study uses the same physical model as Babu and Odeh's model 7 (shown in Fig. 1) because it is more general. The horizontal well is in a box-shaped drainage volume, parallel to the y direction.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 6–8, 1995

Paper Number: PETSOC-95-02

... Abstract The Hibernia Field, located in about 80 metres of water, 315 km ESE of St. John's, Nfld., was discovered i" 1979. Of the 10 wells drilled, seven wells tested a 150 to 290 metre thick section of rock

**interpreted**to have been deposited in a fluvio-deltaic environment. Located between...
Abstract

Abstract The Hibernia Field, located in about 80 metres of water, 315 km ESE of St. John's, Nfld., was discovered i" 1979. Of the 10 wells drilled, seven wells tested a 150 to 290 metre thick section of rock interpreted to have been deposited in a fluvio-deltaic environment. Located between depths of 3450 and 3890 metres subsea, the Early Cretaceous-age Hibernia Formation contains an estimated 1.4 BBbls of STOOIP. Petrophysical properties obtained from wireline logs and core were evaluated using mathematical and statistical techniques to create alternative permeability profiles and to characterize the Hibernia Formation into "Hydraulic Units". A hydraulic unit is defined as a volume of the total reservoir rock within which geological and petrophysical properties that affect fluid flow (e.g. pore tortuosity, surface area per unit grain volume, and shape factor) are internally consistent and predictably different from those properties of other rock volumes. A derivation of the Kozeny-Cannan equation which utilizes overburden core-derived porosity and permeability, was used to construct "Flow Zone Indicator" (FZI) curves. The resulting curves were related to other log attributes using a quantitative probabilistic model to predict hydraulic flow units (and permeability) in wells that had poor or no care recovery. Groupings of flow zones, derived by histogram analysis, were found to be generally coincident with intervals of rock types derived from lithological and paleoecological interpretation. Involving more than just magnitudes of permeability, hydraulic zones provide a fundamental unit for subsequent reservoir characterization and simulation. Discrimination of flow zones will also prove to be helpful in defining future well completion and workover practices. Introduction The Hibernia Field is an offshore oil development located in 80 metres of water, 315 Ion ESE of St John's, Newfoundland. Following its discovery in 1979, nine appraisal wells were drilled from 1980 to 1984. Construction of the Gravity Base Structure (GBS) production platform started in 1990, with initial production scheduled to start in 1997. The Hibernia structure is a complexly faulted, rollover anticline created or influenced by extensional faulting and salt diapirism. The primary reservoir, contained within the Early Cretaceous Hibernia Formation, occurs at an average drill depth of 3700 metres. Of the seven wells which tested the reservoir, five were cored. Sedimentological interpretation of 386 metres of recovered conventional core indicates the Hibernia Formation to be a preserved fluvially-dominated deltaic complex. Quantitative core analysis of 143 metres resulted in reservoir property ranges of 14.5 to 18 percent for porosity, 150 to 2000mD for permeability, and an average water saturation of 13 percent. An integrated geophysical and geological study resulted in the mapping of a reference case distribution of an oil in place resource estimated to be 1.4 billion barrels. As part of a reservoir characterization process, HMDC and CORE Lab investigated the petrophysical attributes of the Hibernia Formation with regard to identifying flow zones. The results of the study provided an alternative assessment of the wells, complementing traditional log analyses that had been done previously. The objectives of the study were twofold: To identify flow zone indicators (FZI) that would characterize the cored intervals in the Hibernia reservoir.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–14, 1994

Paper Number: PETSOC-94-77

... problems for high permeability and porosity sandstone samples, in which the gravitational acceleration distorts the horizontal centrifugal force distribution inside core plugs and thus leads to inaccurate

**interpretation**of capillary pressure information in the high saturation region. The possible remedial...
Abstract

Abstract The most common centrifuges used in the petroleum industry for capillary pressure measurements are made by Beckman. The Beckman centrifuge has, long been found problematic due to its rotor design. The gravity degradation phenomenon at low speeds has been identified as one of the problems for high permeability and porosity sandstone samples, in which the gravitational acceleration distorts the horizontal centrifugal force distribution inside core plugs and thus leads to inaccurate interpretation of capillary pressure information in the high saturation region. The possible remedial countermeasures to this problem may include developing a rotor head with a new configuration that minimizes the effect while maximizing the quality of row experimental data. This paper presents a theoretical analysis of the centrifugal field of rotor systems with pivoted heads. The analysis from the proposed theory shows that a pivoted rotor head makes the gravitational nd centrifugal fields more closely aligned, thereby greatly educing this effect. The new rotor configuration provides n alternative for the centrifuge experiments. A simple approximation is provided to extend the Hassler-Brunner method for use with a pivoted rotor head. Introduction Two of the most important parameters required by petroleum reservoir engineers in order to calculate the performance of oil and gas reservoirs are capillary pressureand relative permeability. Unfortunately, these are he two most difficult parameters to measure. Since the mid-1940'S, 1,2 centrifuges have been used to collect data from which capillary pressure data can be interpreted. The basis of this method is that if a sample of porous edium contains two components, one of which wets the solid, internal surface of the sample, then capillary pressure tends to hold this wetting component inside the sample. If the sample is spun in a centrifuge, the centrifugal force acts to expel the wetting component from the sample, while the capillary pressure forces act to hold the wetting component in the sample. By measuring the amount of wetting component produced as a function of the speed (RPM) at which the sample is spun, a data set may be obtained from which capillary pressure versus saturation may be interpreted. Such interpretations may be very complicated. 3 . In recent years, there has been increasing interest in using a centrifuge to obtain relative permeability. 4 This is done by measuring the rate at which the wetting component is expelled, and interpreting this rate data, again using a complex procedure. 5 Even though centrifuge techniques have been in use for almost 50 years, they have not yet been perfected. Three basic problems remain: obtaining a complete understanding of the mechanisms that are involved in fluid displacement by centrifugal forces, performing true imbibition experiments, and interpreting the data to obtain capillary pressure and relative permeability curves. Considering the first basic problem in particular, two typical phenomena have held people's attention. One is the radial effect due to core width. 6 . Traditionally people assume either a constant or a linear centrifugal acceleration distribution inside the core plug. Such assumptions will cause errors when a short, large diameter core plug is used (unfortunately this is the case for most commercial Beckman centrifuges).

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–14, 1994

Paper Number: PETSOC-94-85

...

**interpretation**could be initiated. This model was refined until a reasonable match was obtained from the horizontal buildup data. Good agreement was achieved between the vertical and horizontal analyses. By utilizing this offsetting data set in the horizontal analysis, a better quality, higher confidence...
Abstract

Abstract During the 1992 facilities turnaround of the Countess Upper Mannville "UU" Pool pressure buildup data was obtained from two vertical wells and one horizontal well. The relatively high permeability of the sand and the proximity of the horizontal well to the top of structure predetermined a lack of early time radial flow response from the horizontal well buildup analysis. The analysis of vertical well buildup response in an offsetting vertical well and information acquired from log and 3-D seismic enabled the generation of a preliminary reservoir model from which the horizontal interpretation could be initiated. This model was refined until a reasonable match was obtained from the horizontal buildup data. Good agreement was achieved between the vertical and horizontal analyses. By utilizing this offsetting data set in the horizontal analysis, a better quality, higher confidence interpretation was achieved. Benefits and limitations of this interpretation technique are discussed. Introduction Pressure transient analysis techniques have progressed significantly in the past fifteen years due to improvements in diagnostic methods through use of the pressure derivative, through rigorous integration of specialized analysis techniques to calculate total interpretation model behavior, through the improvements in pressure gauge accuracy and resolution, and through the increases in available computer power. The limitations of manual techniques such as semi-log methods or type curve matching have been transcended by state-of-the-art integrated computerized analysis methods which have greatly reduced the uncertainty f pressure transient analysis results and the man-lime required to achieve expert level solutions. In the 1990's, the analysis of most classical configurations of wellbore, reservoir and simple outer boundary solutions as been reduced to a simple process for well test analysis specialists. However, coincident to these well test analysis advances, additional research has produced theoretical solutions for an increasing number of complex well and reservoir geometries found in the field. The increasing complexity of pressure transient solutions for composite odels on certain applications produces more solution parameters than unique diagnostic regions on which to tune the variables on an independent basis. Breakthroughs in horizontal well drilling and completion has promoted the successful application of this well orientation to both virgin and mature reserves in North America and throughout the world. The increased productivity from the large horizontal well section within the reservoir bas permitted the exploitation of reserves previously considered to be beyond economic reach. In addition, horizontal wells have been proven to improve weep efficiencies in secondary recovery processes in mature pools. The pressure transient behavior of the horizontal well geometry has been determined by various authors such as Daviau 1 , Goode (2,3) , and Kuchuk (4,5,6) , among others. The application of this theoretical approach to horizontal wells in multi-well pools is the subject of this paper. Anatomy of the pressure transient behavior of an ideal horizontal well The log-log plot of the pressure and pressure derivative profile from an ideal horizontal well producing a single phase fluid from an infinite-acting homogeneous reservoir is set out in Figure la. The transient behavior can be sub-divided into five regions.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–14, 1994

Paper Number: PETSOC-94-52

... Abstract The main aim of well log

**interpretation**is to determine the reservoir geological and petrophysical properties downhole as well as properties fluids and their distributions in a reservoir, and identification of hydrocarbon from well logs is the most important job. Neural networks, with...
Abstract

Abstract The main aim of well log interpretation is to determine the reservoir geological and petrophysical properties downhole as well as properties fluids and their distributions in a reservoir, and identification of hydrocarbon from well logs is the most important job. Neural networks, with their great capability in adaptation and expressing arbitrary complexity, seem especially suited to solve for the reservoir problems where there widely exist uncertainty, fuzziness and nonlinearity. Much work has been published on the identification of lithology and lithofacies from well logs using neural networks. But very few, and almost no work could be found to deal with identifying hydrocarbon from well logs in this neural network approach In this paper, a supervised neural network (a multi-layer perceptron (MLP)) and two unsupervised neural networks (a self-organizing mapping (SOM) net and a fuzzy neural network (FNN) are used to identify oil from well log, and almost each of them can distinguish between oil, water, oil-water transitionand dry zones directly from well logs, but with different accuracy. A case study from a Chinese oil field is given to show their advantages and limitations, and their implementation is also given. The associated oil test results are available to demonstrate their dependability And it is shown that there is a very good agreement between results oil test and oil identification from both LP and FNN. Introduction Generally, the main task of well log interpretation is to determine the geological and petrophysical properties of reservoir rock formation as well as properties of formation fluids and their distributions. Obviously, well logs are the fundamental information source of well log interpretation, and the eventual aim of well log interpretation in oil exploration is to determine both roperties of subsurface fluids and their distribution, which is not directly from well logs and usually based on the predetermined geological and / or petrophysical properties from well logs. During this conventional log interpretation process, it often needs selection of empirical formula and various empirical parameters, which makes the actual log interpretation extremely complicated and subjective, and eventually lead to the extreme difficulty in enhancing the chance of success of well log interpretation. Well log interpretation, in certain viewpoint, is to invert subsurface geological and petrophysical properties, as well as properties of subsurface fluids and their spatial distributions from well logs. And well log responses measured with wireline tools, which reflect the properties of the subsurface reservoir, are in extremely complex relationship with various reservoir properties, because of the high heterogeneity and anisotropy widely existent in reservoir medium. Thus the solution of the conventional log inversion is not of singularity. So, primarily, log analysts could simply interpret well logs qualitatively, aided with their field experience obtained from success and fail by trial and error, that is, visual log interpretation of oil. Because of advances of logging technology and improvement of various experiment techniques as well as introduction of advanced scientific technology such as computers, the log analysts began to quantitatively determine both the properties of subsurface fluids and their distributions from well logs, according to various empirical formula obtained by experiments and various mathematical and physical models established on basis of theoretical analysis, which eventually made well log interpretation grow to be a largely integrated engineering science, that is, the computerized og interpretation stage started when the identi

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–14, 1994

Paper Number: PETSOC-94-53

... Abstract The main aim of well log

**interpretation**is to determine the reservoirgeological and petrophysical properties downhole as well as properties fluidsand their distributions in a reservoir, and identification of hydrocarbon fromwell logs is the most important job. Neural networks, with...
Abstract

Abstract The main aim of well log interpretation is to determine the reservoirgeological and petrophysical properties downhole as well as properties fluidsand their distributions in a reservoir, and identification of hydrocarbon fromwell logs is the most important job. Neural networks, with their greatcapability in adaptation and expressing arbitrary complexity, seem especiallysuited to solve for the reservoir problems where there widely existuncertainty, fuzziness and nonlinearity. Much work has been published on theidentification of lithology and lithofacies from well logs using neuralnetworks. But very few, and almost no work could be found to deal withidentifying hydrocarbon from well logs in this neural network approach In thispaper, a supervised neural network (a multi-layer perceptron (MLP)) and twounsupervised neural networks (a self-organizing mapping (SOM) net and a fuzzyneural network (FNN) are used to identify oil from well log, and almost each ofthem can distinguish between oil, water, oil-water transitionand dry zonesdirectly from well logs, but with different accuracy. A case study from aChinese oil field is given to show their advantages and limitations, and theirimplementation is also given. The associated oil test results are available todemonstrate their dependability And it is shown that there is a very goodagreement between results oil test and oil identification from both LP and FNN. Introduction Generally, the main task of well log interpretation is to determine thegeological and petrophysical properties of reservoir rock formation as well asproperties of formation fluids and their distributions. Obviously, well logsare the fundamental information source of well log interpretation, and theeventual aim of well log interpretation in oil exploration is to determine bothroperties of subsurface fluids and their distribution, which is not directlyfrom well logs and usually based on the predetermined geological and / orpetrophysical properties from well logs. During this conventional loginterpretation process, it often needs selection of empirical formula andvarious empirical parameters, which makes the actual log interpretationextremely complicated and subjective, and eventually lead to the extremedifficulty in enhancing the chance of success of well log interpretation. Well log interpretation, in certain viewpoint, is to invert subsurfacegeological and petrophysical properties, as well as properties of subsurfacefluids and their spatial distributions from well logs. And well log responsesmeasured with wireline tools, which reflect the properties of the subsurfacereservoir, are in extremely complex relationship with various reservoirproperties, because of the high heterogeneity and anisotropy widely existent inreservoir medium. Thus the solution of the conventional log inversion is not ofsingularity. So, primarily, log analysts could simply interpret well logsqualitatively, aided with their field experience obtained from success and failby trial and error, that is, visual log interpretation of oil. Because ofadvances of logging technology and improvement of various experiment techniquesas well as introduction of advanced scientific technology such as computers, the log analysts began to quantitatively determine both the properties ofsubsurface fluids and their distributions from well logs, according to variousempirical formula obtained by experiments and various mathematical and physicalmodels established on basis of theoretical analysis, which eventually made welllog interpretation grow to be a largely integrated engineering science, thatis, the computerized og interpretation stage started when the identi

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 6–9, 1992

Paper Number: PETSOC-92-20

... Abstract This paper summarizes the analysis of wireline formation tester (WFT) data collected in tight gas sands. An

**interpretation**algorithm based on type-curve matching is used in me analysis. The type curves are constructed using an analytical model. The model assumes hemispherical flow...
Abstract

Abstract This paper summarizes the analysis of wireline formation tester (WFT) data collected in tight gas sands. An interpretation algorithm based on type-curve matching is used in me analysis. The type curves are constructed using an analytical model. The model assumes hemispherical flow geometry and incorporates the decompression period and flowline storage effect. The permeability values calculated using this algorithm agree reasonably well with the permeability values available from core and well log analysis. Introduction Pressure data from WFT have been used to determine initial reservoir pressure, vertical pressure distribution, fluid contacts, and formation permeability. Formation permeability is deduced from the pressure behavior observed during either the pretest phase 1–4 or the sampling period. 9,10,13 Whether the flow is into the pretest chamber or into a sampling tank, the fluid flow into a WFT tool is three dimensional and has a convergent flow pattern. The inrerpretation models currently used to calculate formation permeability usually assume spherical or radial flow geometry. The shortcomings of the assumed simplified flow configurations have been documented in the literature. 15 In recent years, several three dimensional (3-D) WFT models have been presented. 11–17 These models take into account the 3-D flow geometry but most of them consider constant flow rate at the sandface. In addition to the flow geometry, several other factors complicate the modeling and analysis of WFT tests: decompression prior to formation flow; flowline storage effect; 16 supercharging effect 16 filtration around the tool packer, and air trapped in flowlines. This paper outlines a hemispherical analytical model. The model incorporates the decompression period and flowline storage effect to account for flow rate change at the sandface. Type curves generated from this model are used to analyze WFT data gathered from tight gas sands. Decompression period The pressure in the WFT tool prior to the test is the hydrostatic mud pressure. The drawdown starts from me hydrostatic mud pressure and me formation does not flow until the pressure in the tool is lowered below sandface pressure. The period from the beginning of the test to the Start of formation flow is referred to as the decompression period. During this period, only the decompression of the fluids due to volumetric enlargement of a closed chamber takes place. Air and drilling mud may exist in the flowline. The existence of trapped air as a separate phase complicates the analysis of WFT data substantially. The simultaneous decompression of air and drilling fluid can be formulated using the mass conservation principle. Equation (available in full paper) The sensitivity of the pressure response to the volume of trapped air 1s investigated using Eq.1. The results of the investigation, in which air is considered as an ideal gas and the data of test 8 in Glasgow #2 is used is displayed in Fig.I. As expected, when there is no gas in the chamber, a perfect straight line is obtained.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, April 20–23, 1991

Paper Number: PETSOC-91-4

... Abstract

**Interpretive**methods for the evaluation of miscible flood performance have been under considerable scrutiny over the last five years, It has been recently, shown that some of the more conventional procedures for miscibility determination might be inadequate for certain oil/solvent...
Abstract

Abstract Interpretive methods for the evaluation of miscible flood performance have been under considerable scrutiny over the last five years, It has been recently, shown that some of the more conventional procedures for miscibility determination might be inadequate for certain oil/solvent systems. Along with these developments, the importance of mechanism identification has been shown. This paper provides an initial review of some of the ambiguities associated with miscible flood interpretation followed by a discussion of the tests commonly used to ascertain miscibility limns. An analysis of experimental procedures is included with a detailed description of the method for maximizing miscibility information. This is done by reference to seven miscible flood designs which the authors have completed over the last two years covering a very diverse set of solvent/oil systems. The specific contributions of flashed liquid compositions, effluent density profiles and dynamic displacement residue analysis are shown pertaining to miscibility classification. As a conclusion, a generic checklist is proposed for evaluation of the type of laboratory program which should be entertained in order to determine miscibility limns. Using this checklist one can determine what types of laboratory tests should be considered, which tests are required, and which are optional. Use of this checklist will tend to optimize the miscible data acquired for the research dollar invested. Introduction Miscible flooding was formally invented in the 1950's according to the literature. The first contact miscible (FCM) process was described by Koch(l) and Hall et al(2). The high pressure vaporizing miscible process was discussed by Whorton et al(3,4,5) and, the condensing mechanism was described by Stone et al(6) and by Kehn(7). Since that time considerable work has been implemented in the laboratory and the field to take advantage of the miscible processes. In the last decade there have been new theories proposed including combined condensing/ vaporizing(B) and Iiquid-liquid extraction(9) mechanisms. Some groups are now beginning to leave the conventional terminology of vaporizing/condensing and dwell more on the pattern of contacting: forward zone and swept-zone contacting for example. Moreover, with the description of new theories regarding miscibility development there has been a revision in some interpretations. Novosad et al(9) show the comparison between original interpretation and a more recent conclusion based on the liquid-liquid extraction theory (Table 1). If the assumed mechanism was erroneous then, in the worst case, what was almost FCM would have been immiscible by the new interpretation. Although a conservative approach dictates a certain degree of overdesign one must be certain that the miscible mechanism assumed is correct in order to make the correct conclusion. Indeed if one misinterprets the miscible lab data and includes a conservative cushion on the solvent design one may still be deficient in the field implementation. This paper discusses laboratory responses from a number of oil-solvent systems covering condensing and vaporizing systems from immiscible (IMM) to FCM. Emphasized herein is the information available from a broad variety of experimental apparatus and how they contribute to conclusive evidence of miscibility.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 9–12, 1990

Paper Number: PETSOC-90-106

... through

**interpretation**of stratigraphic and structural maps and cross sections. 3. Favorable locations within acreage blocks should be delimited through**interpretation**of - a) available drill stem test data, and b) gas and water production rate maps and data with respect to completion techniques and...
Abstract

Abstract Fracture permeability is inferred to be the most important influence on productivity of natural gas from commercial Fruitland Formation coalbed methane reservoirs in the Cedar Hill, Northeast Blanco Unit and Ignacio Blanco Fields of the northern San Juan Basin of Colorado and New Mexico. Reservoir deliverability in these areas with significant coalbed methane resources and reserves is less influenced by thickness, depth, completion technique, and measured and inferred pressure and formation damage. Cleats (coal fractures) in cores from four northern San Juan Basin Gas Research Institute Fruitland evaluation well in these fields formed during coalification in strain fields imparted as a result of Early Tertiary Laramide and Late Tertiary-Recent Rio Grande Rift regional tectonic episodes. These cleats are not the result of sedimentary compaction folding. The presence of discrete, very thin inter-bedded layers of Fruitland coal and non-coal ("ash???") litho types with different respective rock mechanical properties favored brittle deformation of coal layers. Many commercial Fruitland wells are located in areas with extremely minor true structural flexure (folds), which indicates cleat permeability is largely a function of coal composition. Knowledge concerning fracture permeability will influence further delineation and development of northern San Juan Basin Fruitland coalbed methane resources and reserves. The following procedure for qualitative recognition of areas with greater Fruitland permeability prior to drilling is suggested. 1. Preliminary collection and analysis of reservoir description and supporting geological and engineering data from in-house files and public literature should be completed. 2. The geologic setting of available acreage should be determined through interpretation of stratigraphic and structural maps and cross sections. 3. Favorable locations within acreage blocks should be delimited through interpretation of - a) available drill stem test data, and b) gas and water production rate maps and data with respect to completion techniques and formation damage. 4. These areas of interest should be analyzed to find potential drilling locations by finding specific sites that a) required higher Fruitland drilling mud density to prevent blowouts using mud logs, drilling records and mud density maps, and b) have Fruitland coal waters with relatively low total dissolved solids (salinity) and chlorine ion concentrations. 5. Once a drilling location bas been selected, potentially producible coal zones can be determined a) through identification of coal intervals with densities between 12 and 1.75 g/cc on open hole high resolution density logs, and b) by identification of coal intervals with drilling mud invasion through interpretation of micrologs and resistivity log suites from offset wells. Introduction The purpose of this paper is to discuss the importance, genesis, and a suggested procedure for qualitative recognition of fracture permeability in Fruitland Formation (Upper Cretaceous) coalbed methane reservoirs in the Cedar Hill, Northeast Blanco Unit, and Ignacio Blanco Fields of the Northern San Juan Basin of Colorado and New Mexico. Coals that are natural gas reservoirs are termed "coalbed methane" reservoirs because the chemistry of produced gases from such wells is usually methane-rich. Fracture permeability is a crucial component of commercial coalbed methane reservoirs.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, January 1, 1989

Paper Number: PETSOC-89-40-71

... usually attempted by

**interpretation**of resistivity logs. However resistivity devices respond to both mobile and immobile water. The Nuclear Magnetism Log provides a measurement of the Free Fluid Index (FFI) of the formation. FFI represents those fluids that are free to move within the pore space of the...
Abstract

Introduction The bitumen deposits of Alberta contain an estimated 2.6 trillion barrel of hydrocarbon in place and therefore compare to the giant oil fields of the Middle East (ref 3). Unfortunately, the bitumen has viscosities & ranging from 1,000 to 4,000,000 centipoise and will not flow at virgin reservoir temperatures. Despite this, bitumen production rates in Canada are on the rise (seee Figure 1) and are projected to become a substantial portion of the total petroleum output in the future. (ref. 5) A large percentage of the bitumen occurs at burial depths exceeding 300 meters which excludes the possibility of mining. In most cases recovery is by steam injection which lowers the bitumen viscosity steam injection is an expensive proposition so economic bitumen production must rely on two factors - efficient production techniques and a strong oil price. For thermal processes to be successful, it is important that intervals that contain mobile fluids - gas or water - be readily identified. Mobile fluid intervals, if present, have a major impact on the thermodynamics and the resulting operating efficiency of the stimulation process. The identification of mobile water is usually attempted by interpretation of resistivity logs. However resistivity devices respond to both mobile and immobile water. The Nuclear Magnetism Log provides a measurement of the Free Fluid Index (FFI) of the formation. FFI represents those fluids that are free to move within the pore space of the rock. In a shaly sandstone reservoir containing only bitumen and water, the FFI measurement does not include the volume of bitumen, clay bound and capillary bound water. At this point it is important to note that the Free Fluid Index is not mobile water (ie. producible water) in the classical reservoir engineering sense, as water that is free to move within the pore space may not be able to move through the pore throats. However, the results of previous work (ref 7), have indicated that mobile water zones are characterized by FFI readings greater than 5 to 6 porosity units (p.u.). This paper will discuss some of the problems associated with bitumen production. The Nuclear Magnetism log will be introduced and the Free Fluid Index (FFI) will be used to define a petrophysical model. This model will then be implemented in the interpretation of well log data on five wells. THERMAL RECOVERY TECHNIQUES. Although various thermal recovery techniques are available, cyclic steam stimulation is one of the few effective methods of recovering bitumen, Economically the process offers operators the benefits of short term production revenue with minimal risk. Cyclic Steam Stimulation The cyclic steam stimulation process on a single well involves three distinct stages, as illustrated in Figure 2. Steam Injection. Typically steam is injected at rates in the order of 200 cubic meters per day for 30 to 50 days. Steam temperatures in the wellbore are approximately 200 degrees centigrade. In order to achieve these temperatures steam pressures are high. Bitumen zones generally have low injectivity due to low permeability to water, in which case steam pressures are usually sufficiently high to cause formation fracturing.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, January 1, 1989

Paper Number: PETSOC-89-40-10

... with their

**interpretation**for one of the wells to illustrate the analysis techniques. Estimates of the permeability and skin effect from these short-term tests and subsequent production logging measurements are compared to those obtained from earlier conventional tests to assess the effectiveness of...
Abstract

Abstract In this paper we examine the use of simultaneously recorded pressure and flow rate obtained from short duration transient tests performed during perforating operations. Of primary interest in this work is the application of the technique to evaluate the addition of perforated intervals to a thick, partially completed pay zone. The study describes in detail the objectives, test design, data acquisition and analysis of transient tests performed on four producing wells in Uinta. County, Wyoming, before, during and after reperforation operations. A field example presents data along with their interpretation for one of the wells to illustrate the analysis techniques. Estimates of the permeability and skin effect from these short-term tests and subsequent production logging measurements are compared to those obtained from earlier conventional tests to assess the effectiveness of the recompletion operations. The results demonstrate the validity of the tests conducted and their utility in completion evaluation. Introduction Pressure buildup testing as a means to estimate reservoir parameters and to evaluate completion effectiveness is widely practiced in the oil and gas industry. A typical buildup test procedure involves producing a well to stabilization and shutting it in while measuring the downhole pressure. The measured pressures are then analyzed using various graphical techniques, e.g., type-curve analysis, Horner plot, MDH plot, etc. The reservoir pressure response in such tests can often be masked by wellbore storage effects at early times. As a result, correct system identification and reservoir parameter estimation require that tests be conducted long enough for the storage effects to dissipate. In recent years, practical methods have been developed for combining measured downhole flow rates with transient pressure data in order to correct for the wellbore storage effect. 1–3 One method available for analysis of simultaneously acquired flow rate and pressure is convolution, which involves continuous superposition of the pressure response based on an assumed reservoir model and measured flow history. 1,2 The use of convolution and its derivative 4,5 has proven effective in correctly identifying system response and estimating reservoir parameters from early-time data. Field examples 1,3 using production logging sensors have shown that the application of the convolution analysis technique, in conjunction with diagnosis, 6 allows the ability to perform a valid well test of relatively shorter duration. In this study, we show that the Measurement. While Perforating (MWP) tool, with pressure and flow rate measurement capability, can be used during perforating operations to acquire transient data which may be analyzed as a well test for determination of reservoir parameters. 7,8 Also presented is a case study illustrating the interpretation of simultaneously acquired pressure and flow rate in a series of short duration tests before, during and after the addition of perforated intervals to a thick, partially completed pay zone. The tests were performed on four producing wells in the SW Wyoming Thrustbelt Province of Uinta County. Test data and interpretation are presented for only one of hese wells, the others being quite similar. Results are compared with those from previous conventional tests, and are interpreted in conjunction with other production logging measurements to assess the effectiveness of the reperforating operations.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 11–15, 1988

Paper Number: PETSOC-88-39-54

... description of thereservoir model, and confirmation of other analysis techniques. This workdemonstrates that the use of afterflow rates derived from acoustically measuredliquid levels can be used to

**interpret**pressure buildup tests for pumping oilwells. Several different superposition methods are demonstrated...
Abstract

Summary Pressure buildup tests on pumping wells usually have significant afterflowfollowing surface shut in. The measurement and use of this afterflow data hasbeen the subject of much interest as its application can lead to an earlierdetection of a semi-lop, straight line, a more accurate description of thereservoir model, and confirmation of other analysis techniques. This workdemonstrates that the use of afterflow rates derived from acoustically measuredliquid levels can be used to interpret pressure buildup tests for pumping oilwells. Several different superposition methods are demonstrated with fieldexamples. Introduction Pressure buildup data is needed to analyse the character of a reservoir and theproductivity of a pumping well. However. the rods and pumps must be removedfrom the well in order to place downhole pressure recorders. This actionresults in fluid bring dumped onto the formation and loss of early time data.Recorders are sometimes pulled too early, resulting in lack of radial flow dataneeded for semi-log analysis of permeability, skin and average reservoirpressure. Because the time of wellbore storage is often quite long for lowpermeability reservoirs, conventional analysis of such data by type curvematching does not always give conclusive results. An alternative procedure to obtain pressure buildup data for 3 pumping well isto determine the liquid level in the annulus acoustically, measure the surfaceannulus pressure, and calculate the bottomhole pressure.. The procedure allowsone to monitor the buildup from the very start of the test. The method alsogives direct measurement of the wellbore storage coefficient and both liquidand gas afterflow during the test, This technique is described byBrownscombe 1 . The use of afetrflow and pressure data during a buildup test has been thesubject of current interest. Convolution 2–4 and variable rate 5–6 examples are techniques used to reduce well bore storage effects andprovide for reservoir descriptions at an earlier time of buildup. Thesetechniques have primarily been demonstrated with wells producing at arelatively high rate and largely with one phase (cil or gas). The use ofsuper-position techniques for multi-phase pumping wells must consider that boththe bottomhole pressures and afterflows are derived indirectly wellbore andreservoir crossflow coupled with changing wellbore storage coefficients andmulti-phase afterflows does introduce new variables into the analyis. However, consideration of these effects and the measured data quality can producepractical results. Pumping wells are often hydraulically fractured to provide for improvedproductivity. Pressure transient data will diagnose the effectiveness of thefracture job bur early time data is often lost or masked by wellbore storage.The use of the acoustic well sounder provides for an alternative method toanalyse transient data and identify flow regimes during buildup. This work demonstrates the use of pressure and afterflow data derived fromacoustic methods to analyse buildup tests. Several different superpositionmethods are demonstrated with field examples. The use of rate-normalizationtechniques is also presented.

Proceedings Papers

####
**Interpretation** And Use Of Vertically Distributed Pressures From Repeat Formation Tester Measurements

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1986

Paper Number: PETSOC-86-37-36

... becorrected to obtain the true pressure at that depth. These extrapolated andcorrected point pressure measurements, when plotted versus true vertical depth.give invaluable information in both virgin and developed reservoirs. This paper will describe the test by test

**interpretation**and discuss modelsavailable...
Abstract

Abstract Vertically distributed point pressure measurements from a Repeat Formation Tester (RFT ™ ) are used to understand the fluid dynamics anddistribution in the drainage volume surrounding a wellbore. The RFT tool sets apacker at the chosen depth thereby isolating the tool hydraulically from themud column. The RFT probe withdraws fluid from the formation into a fixedvolume resulting in a pressure drawdown. The ensuing build-up is analyzed usingspecific solutions to the diffusivity equation. This test by test analysis, which can also be done at the well site, uses solutions to the diffusivityequation in spherical and cylindrical co-ordinate systems. An extrapolatedpressure for that depth and an estimate of spherical mobility is obtained. Ifthe effect of supercharging (a localized zone of over-pressure caused by thefiltration process) is significant, the extrapolated pressures for that to becorrected to obtain the true pressure at that depth. These extrapolated andcorrected point pressure measurements, when plotted versus true vertical depth.give invaluable information in both virgin and developed reservoirs. This paper will describe the test by test interpretation and discuss modelsavailable to estimate excess pressures due to supercharging. It will alsoillustrate, using examples where possible, the estimation of fluid gradients, de-lineation of transition zones and insight into rock wettability by carryingout a Free Water Level Analysis on RFT pressures from virgin reservoirs. Fordeveloped reservoirs examples of differential depletion and non-uniformwater-flood conformance will be presented. Introduction The predecessor of RFT was the wireline formation tester commonly known as(FIT ™ ). To analyse the pressure-time behaviour during the pressurebuild-up which followed the drawdown of fluid into the FIT, spherical flowsolutions tothe diffusivity equation were required. Moran and Finklea(1) solvedthe diffusivity equation for spherical flow geometry for both constant How rateand constant pressure at the inlet to the tool. The equation to analyse thebuild-up following the constant flow rate period was also presented. Stewartand Wittman[2] used the constant flow rate spherical geometry Solution[1] andformulated the build-up equation which can analyse the pressure-time historyafter two constant flow rate periods. These two constant Bow rate periods arecharacteristic. of RFT and are also known as the two pre-tests. The RFT tool was presented in the petroleum engineering literature by Schultzet. al.[4]. They gave field examples of pressure measurements and sampling.Emphasis in their paper was the multiple setting capability of the tool forpressure measurements. Reservoir Engineering applications of verticallydistributed pressure measurements were presented by Smolen &: Lirsey[5].Based on RFT pressure profiles they were able to monitor a waterflood better.Applications for the Middle East and Canada were presented[6][7] in 1979. This paper in addition to reviewing the interpretation theory for an individualtest will also present some recent field example from Canada, These examplesare from exploration and development wells. Vertical pressure profiling andestimate of effective permeabilities are the basic products from RFTmeasurements. This paper will propose new applications which using RFTmeasurements, may give insight into the wettability characteristic of therock.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 9–12, 1984

Paper Number: PETSOC-84-35-92

... reasonable p ∗. A longer shut-in does not correct the problem unless it is preceded by a longer flow period. The use of "equivalent time" to account for the short flow period introduces problems of its own. Introduction In most oil or gas well test

**interpretations**, it is important to determine if the data...
Abstract

Abstract If the duration of the flow period preceding a buildup test is not sufficiently long an apparent semi-log straight line may still be seen both on a type curve match and a Horner plot. The analysis of this semi-log straight line results in the wrong value of permeability but a reasonable p ∗. A longer shut-in does not correct the problem unless it is preceded by a longer flow period. The use of "equivalent time" to account for the short flow period introduces problems of its own. Introduction In most oil or gas well test interpretations, it is important to determine if the data obtained are such that a meaningful semi-log analysis can be performed. In recent years, this has been done by "typecurve matching" the data and noting, from the typecurve, the approximate start of the semi-log data. Once this has been determined, the data following that point are analyzed by selecting a semi-logarithmic straight line, the slope of which can be used to determine the transmissibility of the reservoir. The curves used for "typecurve matching" are, generally, derived from drawdown tests but they can be used for buildup tests if the data are first desuperposed. When rigorous desuperposition can not be done, an approximate method is often used, which is usually adequate for determining the approximate start of the semi-log straight line for use with Horner or similar plots. In a large number of buildup tests recently analyzed by the authors, it was observed that, often, two tests on the same well gave significantly different results of interpretation. The method of interpretation was the same for both tests, namely: from the typecurve match, determine the approximate start of the semi-log straight line, and then use that in the Horner analysis. Both sets of desuperposed data showed the presence of an acceptable semi-log straight line. The principal difference between the two sets of tests was the duration of the flow period - one was significantly longer than the other. Why were the interpretations so different? and which one is the correct one? Model In order to resolve the problem a theoretical investigation was undertaken. Pressure buildup datawere simulated for flow periods of varying durations and these synthetic pressures were then analyzed by the standard methods. The reservoir model selected for this presentation is that of an infinite, homogeneous reservoir with a vertically fractured well - the fracture has an infinite conductivity, and wellbore storage is considered to be negligible. Such a model fits a very large number of wells which have been hydraulically fractured. The solution - in dimensionless terms - for this model was presented by Gringarten, Ramey and Raghavan in 1972 (ref 1) and is shown in "typecurve matching" format in Figure 1. This solution applies to a constant rate drawdown but it can be used, with the principle of superposition, to derive buildup information for any shut-in time Δt, following a flow period of duration t. (ref 2) Equation (1) (Available In Full Paper)

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 5–8, 1982

Paper Number: PETSOC-82-33-53

... amounts of rock samples. 5–10g of the rock was crushed and thoroughly ground in dehydrated methanol in an inert atmosphere of nitrogen gas. The water andsalt in the rock was extracted by methanol and a known volume of the solution was made.

**interpretation**salinity water saturation substantial...
Abstract

Abstract Laboratory determined salinities of water extracted quite different pore systems in terms of microfrom oil base cores recovered from the Elmworth porosity and bound water. area showed variations from as low as 6,000 ppm to over 60,000 ppm (NaCl eq.). It was observed that low salinities were associated with reservoirzones characterized by high cation exchange capacities and substantial feldspar content. By contrast, clean quartzose sandstones yielded relatively high salinities. Thin section and Scanning Electron ~Microscope examinations reveal that diagenetic processes affecting the feldspathic sandstones have produced significant quantities of secondary clays, especially chlorite, kaolinite and subsequent illite. As a result, the lithologic differences have been enhanced, leading to quite different pore systems in terms of microporosity and bound water. Application of a Dual Water type model of shaly sands in conjuction with laboratory determined water saturation, porosity and cation exchangecapacity allowed estimation of free water salinity. This salinity was found to be in reasonable agreement with the salinity of produced waters. Log derived water saturations are generally in good agreement with laboratory derived values. Introduction Formation water resistivity, R w , is required for the determination of in-situ water saturation from resistivity logs. It is generally estimated from salinities of produced waters or from aconsideration of log responses in water saturated zones. Alternatively, R w may be derived from salinities of waters extracted from oil base cores. However, because such waters are likely to be d mixture of "free" (or "formation") water and fresher "clay bound" water, 2, 3 measured salinities must be corrected before being employed in log analysis calculations. An accurate knowledge of in situ water saturation is necessary to calculate hydrocarbon reserves of a reservoir, particularly for low permeability sands which are at the limit of economic producibi1ity. We have demonstrated that the laboratory determined salinity of the connate water of reservoir rods is the mean water salinity of the waterbound to the clay surface and that of free water. Depending upon the degree of shaliness of the rock, the laboratory determined salinities were generally found to be 1ower than the actual salinity of the produced formation water. Twenty three samples were selected from cores cut in oi1 base mud in the Elmworth Area of the so called "Deep Basin" of Western Canada. Porosity, cation exchange capacity (CEC), water saturation and water salinity were measured on each sample. Measured water salinities were then corrected for dilution by clay water, using a "Dual Water" shaly sand model, 2, 3 and compared with produced watersalinities. EXPERIMENTAL PROCEDURES Micro Extraction Salinity Determination Technique We have developed in our laboratory a technique or the determination of the volume of connate water and its salinity for small amounts of rock samples. 5–10g of the rock was crushed and thoroughly ground in dehydrated methanol in an inert atmosphere of nitrogen gas. The water andsalt in the rock was extracted by methanol and a known volume of the solution was made.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, May 2–5, 1981

Paper Number: PETSOC-81-32-51

... hundredproducing gas reservoirs are included in the program. This paper describes the form of the gas reservoir performance plots being used in the NEB monitoring program. Typical examples are presented. The

**interpretation**and use of the plots in identifying performance problems are discussed. Introduction...
Abstract

Abstract As an ongoing function the National Energy Board monitors the performance of producing gas reservoirs throughout Canada. Recently computerized plotting of reservoir performance data has allowed this monitoring program to be made more comprehensive and currently more than three hundredproducing gas reservoirs are included in the program. This paper describes the form of the gas reservoir performance plots being used in the NEB monitoring program. Typical examples are presented. The interpretation and use of the plots in identifying performance problems are discussed. Introduction Government agencies, such as the National Energy Board, in serving the public interest, have the task of maintaining an accurate estimate of domestic energy reserves. In Canada, gas reserves contained in a multitude of individual pools are amajor component in the total energy package. New technical information concerning these gas reserves is continually being generated by exploration and development drilling and operating experience in producing reservoirs. The task of assessing the impact of this new information on reserves estimates is not a small one. Monitoring programs which enable resources to be channeled for maximum effectiveness play an important role. The computerized production data files of the provincial agencies of the oil and gas producing provinces in Canada contain a large amount of information concerning producing gas wells. This information can be rapidly retrieved and presented in anyone of a variety of formats using computer graphics, a process which is well-known and widely used. Recently the NEB's gas reservoir performance monitoring program has been expanded by the use of computer graphics. The computer generated performanceplots of this program are similar, except perhaps in a few minor details, to those used by most oil and gas companies in their reservoir evaluation work. They merely present raw data required for pressure and production rate decline analyses along with the water/gas ratio history. To date more than three hundred gas reservoir performance plots have been prepared, which represent a large portion of Canada's initial reserves of conventional gas. The sheer volume of information presented in graphical form has permitted some interesting observations and conclusions of an empirica1 nature. RESERVOIR PRESSURE DECLINE The material balance equation expresses the relationship between the stabilized shut-in reservoir pressure (P) and the cumulative production (q). For a volumetric gas reservoir the relationship is: Equation (1) (Available in full paper) It is usual to present the material balance graphically as a plot of P/Z versus Q. For a volumetric reservoir the plot can be extrapolated linearly to obtain an estimate of the initial gas-in-place (Q i ) as the x-axis intercept and of the recoverable serves (Q i ) as the value of Q at the abandonment P/Z (Ref. 1). The practical application of the material balance relationship is not without its difficulties, In low-permeability reservoirs prohibitively long shut-in times may be required in order to directly measure stabilized shut-in pressures (Ref. 12). In such cases a value must be estimated by build-up analysis (Ref. 2, 3).