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Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, October 1–4, 2000

Paper Number: SPE-63071-MS

... drilling fluid chemistry formation testing drilling fluid formulation upstream oil & gas ofa log coloration

**buildup****curve**obm filtrate real-time determination drilling fluid property contamination**buildup****curve**openhole wireline procedure lab result Copyright 2000, Society of Petroleum...
Abstract

Abstract The key objectives of openhole wireline sampling are to identify desiredfluids and to collect representative formation samples. Optical methods such asvisible - near-infrared spectroscopy (NIR) are used to identify and quantifymixed oil, water, and gas flows in-situ during wireline logging. In wellsdrilled with oil based muds (OBM) or synthetic based muds (SBM), differentiating crude oil from the filtrate base fluid is critical. The widely used current practice is to measure the increase in fluid coloration (by NIR)vs. time to qualitatively assess the increasing fraction of crude oil with pumping time. Here, we describe new methods of utilizing NIR log data toprovide quantitatively during sampling the %-OBM contamination in the extracted fluid. In addition, these methods allow prediction of contamination at futuretimes during the sampling job, thereby determining the effectiveness of further pumping. The significant improvement in sampling efficiency is demonstratedwith several log examples. Finally, using our methods, mud performance in the downhole environment can be monitored and optimized in subsequent jobs. Introduction Hydrocarbon properties vary over a huge range, from dry natural gas toviscous tars at the extremes. Hydrocarbon components such as wax, asphaltenes, and gas as well as their phase behavior have an inordinate impact on productionstrategies. Open hole sampling is an effective way to acquire representative reservoir fluids. Sample acquisition allows determination of criticalinformation for assessing the economic value of reserves. In addition, optimal production strategies can be designed to handle these complex fluids. Inopenhole sampling, initially, the flow from the formation contains considerable filtrate, but as this filtrate is drained, the flow increasingly becomes richerin formation fluid. 1,2 Sampling in wells drilled with water based muds is efficiently performed. NIR spectroscopy can readily distinguish watervs oil, thus indicating when sampling should take place; 2 small quantities of water are easily separated from crude oil in the lab providing representative formation crude oil samples. In addition, gas detection usingoptics determines that sampling is performed at pressures higher than bubble point assuring representative sampling. 3 Sampling in wells drilled with OBM and SBM represents a particular challenge. (For our purpose, SBM and OBM behave similarly, so we will referonly to OBM but SBM's apply also.) The OBM (and SBM) filtrate is miscible withcrude oil, thus cannot be separated. Greater than 10% contamination of thecrude oil sample by OBM filtrate makes it difficult to determine virgin crudeoil properties. 1 In addition, proper extrapolation to virgin crudeoil properties from measured properties of contaminated samples requires accurate determination of contamination. Contamination estimation is difficult to perform as evidenced by common discrepancies among different lab analyses. It is best to reduce the contamination to low levels during sampling, yieldingclean samples requiring little parameter extrapolation. However, it is notacceptable to pump indefinitely to reduce contamination levels because rig timefor OBM wells is often very expensive and the chances of tool sticking can onlyget worse with lengthy pumping times. Also, in some cases, contamination levelsremain stubbornly high even after extended pumping.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 16–19, 1984

Paper Number: SPE-13079-MS

... flow we only need the shape factor in addition to the area. If we use the direct approach, and assume that the asymptote is equal to the average pressure, then we need the same type of information to make a proper choice of interval where the hyperbola should match the

**buildup****curve**. For the direct...
Abstract

The paper was presented at the 59th Annual Technical Conference and Exhibition held in Houston, Texas, September 16–19, 1984. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write SPE, 6200 North Central Expressway, Drawer 64706, Dallas, Texas 75206 USA. Telex 730989 SPEDAL. Summary This paper examines applicability and limitations on the use of rectangular hyperbolas to analyze pressure buildup data, with emphasis on the pressure buildup data, with emphasis on the determination of average pressure and flow capacity. It is shown that the method can be used with confidence only if it is applied to data that can also be analyzed by conventional semilog methods, and that it for such data is essentially equivalent to the conventional methods in terms of information needed and information obtained. If we use semilog data, then we can determine the flow capacity from the slope of the hyperbola, and we can determine the average pressure indirectly from the asymptote, provided we pressure indirectly from the asymptote, provided we know the drainage area and the MBH function of the reservoir. Following stabilized flow we only need the shape factor in addition to the area. If we use the direct approach, and assume that the asymptote is equal to the average pressure, then we need the same type of information to make a proper choice of interval where the hyperbola should match the buildup curve. For the direct approach we will normally get an estimate of average pressure that is less than m/1.151 psi (kPa) above the last wellbore pressure being used in the analysis, where m is the conventional semilog slope. Moreover, if we use only semilog buildup data following pseudosteady-state flow, then we can only get an accurate estimate of average pressure by this approach if the shape factor is close to 21, or higher. If nothing is known about the reservoir, then the hyperbola method can be used to get a rough estimate of the average pressure, but with a high degree of uncertainty if we only have data from a short buildup period. This claim follows from the many examples period. This claim follows from the many examples included in this paper of asymptotes determined from hyperbolas matched to dimensionless synthetic buildup data plotted vs. interval midpoints. Introduction The Miller-Dyes-Hutchinson (MDH), Matthews-Brons-Hazebroek (MBH), and Dietz methods can be used to determine the average, or static, reservoir pressure for closed reservoirs, and the method of Kumar and Ramey can be used for constsant-pressure squares. These methods are based on an indirect use of exact pressure solutions, and hence require knowledge of the size and shape of the drainage area, and of the outer boundary condition. For a given test, all or part of this information might be missing, in which part of this information might be missing, in which case approximation must be used to carry out the analysis. This leads to uncertainties in estimates of average pressure and other parameters that depend on this information. A different approach to pressure buildup analysis was suggested by Mead. He observed that pressure buildup curves closely resemble rectangular hyperbolas, and therefore asserted that the average reservoir pressure should be equal to the horizontal a sympotote of a hyperbola matched to a buildup curve. Mead supported his assertion by examples. Hasan and Kabir explored Mead's empirical results further, and presented a theoretical justification for the hyperbola approach to buildup analysis when both the drawdown and buildup transients are in the inifinte-acting period. Their work was based on a truncated series expansion of the logarithmic solution. Hasan and Kabir successfully and flow conditions, and concluded that the rectangular hyperbola approach can generally be used to determine the average, or static, reservoir pressure directly from field data, and also that good pressure directly from field data, and also that good estimates can be obtained for flow capacity and skin. This without prior knowledge of the size, shape, and type of the reservoir being tested. An analysis of the inherent limitations on the method was not included in Ref. 6. The general conclusions in Ref. 6 attracted criticism from Humphreys and Bowles and White. In their replies, Hasan and Kabir acknowledged the superiority of Horner analysis of infinite acting reservoirs, but reaffirmed the validity of the method for other cases, again supported by examples.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 21–24, 1980

Paper Number: SPE-9289-MS

... type curves for analyzing buildup data for a radial flow system. Drillstem Testing time effect buildup type curve limitation drillstem/well testing analyze pressure buildup producing time

**buildup****curve**new method Pressure Buildup data Gringarten buildup data type curve Upstream Oil...
Abstract

Abstract Currently, type curve analysis methods are being commonly used in conjunction with the conventional methods to obtain better interpretation of well test data- Although the majority of published type curves are based on pressure drawdown solutions, they are often applied indiscriminately to analyze both pressure drawdown and buildup data. Moreover, the limitations of drawdown type curves, to analyze pressure buildup data collected after short producing times, are not well understood by the practicing engineers. This may often result in an erroneous interpretation of such buildup tests. While analyzing buildup data by the conventional semi-log method, the Horner method takes into account the effect of producing time. On the otherhand, for type curve analysis of the same set of buildup data, it is customary to ignore producing time effects and utilize the existing drawdown type curves. This causes discrepancies in results obtained by the Horner method and type curve methods. Although a few buildup type curves which account for the effect of producing times have appeared in the petroleum literature, they are either limited in scope or somewhat difficult to use. In view of the preceding, a novel but simple method has been developed which eliminates the dependence on producing time effects and allows the user to utilize the existing drawdown type curves for analyzing pressure buildup data. This method may also be used to analyze two-rate, multiple-rate and other kinds of tests by type curve methods as well as the conventional methods. The method appears to work for both unfractured and fractured wells. Wellbore effects such as storage and/or damage may be taken into account except in certain cases. The purpose of this paper is to present the new method and demonstrate its utility and application by means of example problems. Introduction Type curves have appeared in the petroleum literature since 1970 to analyze pressure transient(pressure drawdown and pressure buildup) tests taken on both unfractured and fractured wells. The majority of type curves which have been developed and published to date were generated using data obtained from pressure drawdown solutions and obviously are most suited to analyze pressure drawdown tests. These drawdown type curves are also commonly used to analyze pressure buildup data. The application of drawdown type curves in analyzing pressure buildup data is not as bad as it may first appear. As long as the producing time, t, prior to shut-in is sufficiently long compared to the shut-in time, Delta t [that is (t +Delta t)/t 1], for liquid systems, it is reasonable to analyze pressure buildup data using drawdown type curves. However, for cases where producing times prior to pressure buildup tests are of the same magnitude or only slightly larger than the shut-in times [that is, (t + Delta t)/t »1], the drawdown type curves may not be used to analyze data from pressure buildup tests. The above requirement on the duration of producing times is the same for the conventional semi-log analysis. If pressure buildup data obtained after short producing pressure buildup data obtained after short producing time are to be analyzed, the Horner methodic is recommended over the MDH (Miller-Dyes-Hutchinson)method. The MDH method is generally used to analyze buildup data collected after long producing times, whereas the Horner method is used for those obtained after relatively short producing times. Although pressure buildup tests with short producing times may occur often under any situation, they are rather more common in the case of drill stem tests and prefracturing tests on low permeability gas wells. Thus, there is a need for generating buildup type curves, which account for the effects of producing time. Some limited work has been done in producing time. Some limited work has been done in this regard. McKinley has published type curves for analyzing buildup data for a radial flow system.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Fall Technical Conference and Exhibition, October 1–3, 1978

Paper Number: SPE-7427-MS

... & Gas Thickness bounded reservoir Laplace transform straight line composite reservoir recovery efficiency Van Everdingen Efficiency infinite

**buildup****curve**infinite reservoir reservoir pressure increase permeability SPE 7427 RECOVERY EFFICIENCY by A. F. van Everdingen, Member SPE-AIME...
Abstract

Abstract For the past 50 years, data on recovery efficiency have been collected and organized on the basis of discovery year; in reviewing these data, we note that the efficiency has declined during the last three decades. The modern petroleum industry was born in the U.S.A. In this country, all tools are readily available; many ideas on recovery efficiency have originated here and have been put into practice with results reported. Therefore, we fail to understand why the average efficiency is 30 percent when the best of the fields has a recovery of close to 90 percent. We could argue that the data for the last 10 years are still incomplete; this argument might explain the low figures for recent years. However, no such argument can be advanced for the reservoirs found 10 years ago or earlier. Moreover, the decrease in efficiency occurred during a period in which the usefulness of Schlumberger logs came to be fully recognized, in which the flow of reservoir fluids was better understood, and in which powerful computers became available and were used extensively for a rapid analysis of any situation. Possible Explanations Possible Explanations The decrease in efficiency might be explained by: We were apt to consider formations as homogeneous when in fact they were not. We have been unable to properly assess the effect of layering overwide distances. We had an incomplete understanding of and explanation for the skin effect. We have failed to use pressure and production data effectively. We have not kept reservoir pressures at the desired level, giving the Jamin effect an opportunity to develop. We have, in many instances, used well spacing that is too wide. Introduction 1937 saw the first report on the reserves in the U.S.A., "Proved Reserves of Crude Oil, Natural Gas Liquids and Natural Gas," prepared under the auspices of the API and AGA; the report subsequently was issued yearly. Throughout World War II and most of the postwar years, the reviews contained only two categories: "Changes in Proved Reserves Due to Extensions and Revisions" and "Proved Reserves in New Pools." These categories were unchanged until 1966 when the API's work with respect to proved reserves was expanded to include the development of estimates for proved reserves was expanded to include the development of estimates for crude oil as follows: original oil in place and ultimate recovery categorized by geologic age of reservoir rockb. reservoir lithologyc. type of entrapment; indicated additional reserves from cased-off reservoirs and from future installation of fluid injection projects in known fields; allocations back to year of discovery of current estimates of ultimate recovery current estimates of original oil in place; reserves and production data by subdivision for the states of California, Louisiana, New Mexico, and Texas; crude oil productive capacity in the United States. The report format has not been revised since 1966. During each year, the existing data on any state or portion thereof are reviewed by a small group of engineers and geologists. This group also prepares the first estimates for new discoveries and extensions of oil prepares the first estimates for new discoveries and extensions of oil fields. The findings of all the groups (totaling some 120 people) are discussed in a special meeting of the reserves committee each spring. The data agreed upon are assembled by the API office in Washington, D.C.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Fall Technical Conference and Exhibition, October 9–12, 1977

Paper Number: SPE-6756-MS

... well. When this is true, the shape of the pressure

**buildup****curve**is indicative of the type of discontinuity present in the reservoir. This paper presents the results of a study conducted to determine the influence of production time and reservoir discontinuities on the shapes of pressure**buildup****curves**...
Abstract

Abstract Most of the theory developed to date concerning pressure buildup in wells located near reservoir pressure buildup in wells located near reservoir discontinuities assumes that production times prior to buildup were long enough for the discontinuity to influence the pressure drawdown behavior of the well. When this is true, the shape of the pressure buildup curve is indicative of the type of discontinuity present in the reservoir. present in the reservoir. This paper presents the results of a study conducted to determine the influence of production time and reservoir discontinuities on the shapes of pressure buildup curves. It is shown that pressure buildup curves. It is shown that insufficient flow time can lead to anomalous behavior in the buildup curve. For example, the buildup curve from a well located near a sealing fault shows the customary two-to-one slope change when the production time prior to buildup is long enough for the flowing bottom-hole pressure to be affected by the fault. A buildup taken pressure to be affected by the fault. A buildup taken on the same well following a shorter flow period shows a reduction in slope when the fault begins to influence the test. This latter behavior could be incorrectly interpreted as showing an improvement in transmissibility some distance from the well. Similar behavior can be seen in buildup tests on wells producing from reservoirs containing various types of producing from reservoirs containing various types of radial and linear discontinuities. Examples are given for various types of reservoirs. Introduction Conventional buildup theory for evaluation of linear discontinuities demonstrates the presence of a single slope change in the Horner buildup plot. The nature of the slope change is dependent upon the type of linear discontinuity. It can range from a two-to-one change associated with no-flow barriers to a final slope approaching zero for a constant pressure barrier. A similar approach has been published for radial-type discontinuities. In cases published in the literature, the flow times prior to the shut-in have been sufficient to insure that the drawdown already has felt the presence of the discontinuity. The purpose of this paper is to examine buildup behavior when flow time prior to the shut-in has been insufficient to be affected by linear and radial discontinuities. Data presented show the existence of several slope changes in the pressure buildup plots, which are contrary to conventional belief. In addition, the slope measured from the buildup data is affected also by the duration status of drawdown prior to shut-in. The techniques presented make use of image wells, the radial flow equations, and the superposition principle. For radial discontinuities, published principle. For radial discontinuities, published type-curves are used. BASIC THEORY The fundamental theory is based on the point-source solution to the radial diffusivity equation. point-source solution to the radial diffusivity equation. The solution is (1) (2) Then the above equations read (1a) (2a) Infinite Reservoir A schematic diagram is shown as Fig. 1. For the infinite reservoir, no discontinuity exists.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Fall Technical Conference and Exhibition, October 3–6, 1976

Paper Number: SPE-6055-MS

... performance when conventional analysis methods cannot be used. Upstream Oil & Gas flow rate drillstem/well testing Drillstem Testing Mcf day short time production test production test afterflow method

**buildup****curve**afterflow plot stimulation buildup wellbore transmissibility ratio...
Abstract

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract The actual production performance of a number of wells have been compared to predictions made by the McKinley afterflow analysis of drill stem test and short time production test data on these wells. Many formations are tested for short time periods that do not give sufficient or periods that do not give sufficient or conclusive data for reservoir analysis by conventional methods thereby necessitating use of an afterflow method. The example wells in this study show low permeability, wellbore damage, two zones permeability, wellbore damage, two zones with a large contrast in permeability, artificial stimulation and naturally occurring fracture systems with a tight matrix. Example plotted curve shapes of the above conditions are illustrated along with a discussion of how to recognize and use each. Limitations as well as the applications of the McKinley afterflow method are discussed. The most important use of the McKinley After-flow Method is the ability to predict the tight matrix production rate of a well after a stimulated wellbore area has been depleted. Comparison of drill stem test analysis before completion with production test analysis after completion on the same well give comparable answers. Data on a group of wells selected from South Texas, the Permian Basin and Rocky Mountain areas have been furnished by the industry and the results are shown in Table 3. Illustrations of D.S.T. charts, Horner plots, McKinley plots and production decline curves are shown plots and production decline curves are shown for most examples. The conclusions reached from this study show the McKinley afterflow method gives reliable predictions of reservoir performance when predictions of reservoir performance when conventional analysis methods cannot be used.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Fall Technical Conference and Exhibition, October 3–6, 1976

Paper Number: SPE-6130-MS

... parameters from pressure

**buildup****curves**for an infinite two- layered oil reservoir. Equations were derived that define the pressure behavior at the wellbore. Pressure drop equations were derived for the upper and lower zones using Hartsock's method.2 From these pressure drop equations, other equations were...
Abstract

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract The purpose of this study is to obtain a set of expressions and procedures that can be used to determine the reservoir parameters from pressure buildup curves for an infinite pressure buildup curves for an infinite two-layered oil reservoir. Equations were derived that define the pressure behavior at the wellbore. Pressure drop equations were derived for the upper and lower zones using Hartsock's method. From these pressure drop equations, other equations were derived that describe theoretical buildup for this system when the well is shut in. From these equations it is possible to determine the initial pressure of one zone the other initial pressure or the difference between the two initial pressures of the respective zones are known. The effective permeabilities can also be computed under the permeabilities can also be computed under the above conditions; that is, if the initial pressure in either zone is known or if the pressure in either zone is known or if the difference in pressure between the two zones is known. Hartsock used only the pressure drop of the upper zone for these derivations and determinations, but this study shows that from the pressure drop and shut-in pressure equations, equations can be derived to determine the skin factors for the upper and lower zones. This study also shows under what conditions an infinite two-layered oil reservoir is similar to a single-layered reservoir. Hartsock and Lefkovits et al. methods have been used to show the effects of permeability and thickness ratios on pressure buildup permeability and thickness ratios on pressure buildup curves. Also studied were the effects of skin and wellbore storage using the equations derived for an infinite two-layered reservoir with boundary conditions at the wellbore outlined by Lefkovits et al. Introduction The pressure buildup analysis considered in this study is that of an infinite two-layered reservoir without crossflow. So far, equations have not been developed to obtain the pressures, permeabilities and skin factors for the permeabilities and skin factors for the individual zones of two- or more-layered reservoirs. Lefkovits et al. studied the behavior of bounded reservoirs composed of stratified layers. Their work showed that the time necessary to reach pseudo-steady state is much longer for a two-layer reservoir than for a single-layer reservoir.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, September 28–October 1, 1975

Paper Number: SPE-5590-MS

... interpretation pressure buildup

**buildup****curve**successful matrix SOCIETY OF PETROLEUM ENGINEERS OF AIME 6200 North Central Expressway Dallas, Texas 75206 PAPER SPE NUMBER 5590 THIS PRESENTATION IS SUBJECT TO CORRECTION Successful Matrix Requires a Reliable Acidizing of Sandstones E s t i mate o f W e·l I b...
Abstract

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract Successful matrix acidizing of sandstones for the removal of wellbore damage is dependent on a reliable estimate of wellbore "skin" and its radial extent. The value of these parameters is estimated from pressure-buildup parameters is estimated from pressure-buildup analysis. However, in depleted, multilayered reservoirs, the values obtained may vary considerably depending on the chosen method of pressure-buildup interpretation. pressure-buildup interpretation. For this study, pressure buildups before and after acidization were analyzed by both the semisteady-state solution of Horner and early time analysis of McKinley. These results were compared with the actual field results. It may be concluded that the early time analysis of McKinley gave more probable results, but it should be stressed that, under these reservoir conditions, there is no absolute answer, and results from independent methods should be compared. Introduction At present, Cia. Shell de Venezuela is involved in an active stimulation program to optimize oil potentials from their Lake Maracaibo sandstone reservoirs. The choice of candidates and treatment design depends on a series of factors, but perhaps the most important is the extent of wellbore damage. In the Horner method currently used, the skin factor and reservoir permeability are both determined by the slope of the linear portion of the buildup curve. If the linear portion of the buildup curve is chosen incorrectly, the calculation will yield either an excessive skin together with an overestimate of reservoir permeability or an underestimate of wellbore permeability or an underestimate of wellbore damage and a reduced reservoir permeability. The present trend to "minifracs" (small frac treatments with sand using gelled gas oil as carrying fluid) for removal of wellbore damage does not depend too heavily on correctly interpreting the damage factor as the oil gains result from two mechanisms: skin removal if it exists, and increasing the natural permeability in the nearby area of the well or permeability in the nearby area of the well or even fracturing into sands of improved permeability. permeability.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, October 8–11, 1972

Paper Number: SPE-4123-MS

... well bore stimulation and productivity. The Horner pressure buildup method is gener- ally accepted as the best means of deter- mining reservoir data from short time tests such as a drill stem test. The Horner method requires that the steady state or straight line portion of the

**buildup****curve**be reached...
Abstract

This paper was prepared for the 47th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in San, Antonio, Tex., Oct. 8–11, 1972 Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract In a wildcat well or early in the life of a reservoir, drill stem test data is quite often the only means available to estimate reservoir values of transmissibility, effective permeability, well bore damage, well bore permeability, well bore damage, well bore stimulation and productivity. The Horner pressure buildup method is generally accepted as the best means of determining reservoir data from short time tests such as a drill stem test. The Horner method requires that the steady state or straight line portion of the buildup curve be reached. For various reasons, approximately 25% of all drill stem tests run do not meet this requirement. This group of wells are the ones with the highest economic risk involved in making a decision on whether to abandon or complete. A 1971 paper published by Mr. McKinley, "Transmissibility from Afterflow Dominated Pressure Buildup Data", gives a means to Pressure Buildup Data", gives a means to calculate reservoir values when pressure buildup curves are still under the influence of afterflow. A research program was recently completed using drill stern test data to calculate transmissibility and effective permeability by the McKinley method and to compare the results obtained against the Horner method. Fifty drill stem tests were chosen for analysis that had an appreciable afterflow period and steady state period on the same buildup curve. The comparison of results was very close as long as the basic assumptions were not deviated from too far. Most drill stem tests, where it is necessary to use the afterflow buildup method, do deviate considerably from these basic assumptions. Therefore, it is necessary to use a correction factor in interpreting the afterflow method.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, October 4–7, 1970

Paper Number: SPE-3016-MS

... factor. q = flow rate prior to shut-in, bbls/day. drillstem/well testing bixel van Poollen flow in porous media Fluid Dynamics field example straight line portion Drillstem Testing approximation intersection buildup

**buildup****curve**shut-in time transmissibility equation straight...
Abstract

Abstract Pressure build-ups from properly conducted drill stem tests have provided the well owner an ever increasing amount of useful data in regard to formation evaluation. The distance to a discontinuity is a significant formation parameter that can be calculated from drill stem test data. This study investigates the various methods available for calculating the approximate distance to a discontinuity. The transient response curves obtained during a drill stem test exhibit more than one slope if the flow periods and shut-in periods are sufficiently large. The distance to the discontinuity can be calculated by picking the point of deviation from the straight line portionT +0 of a well bore pressure vs. log ------ plot.0 Calculations are shown for a theoretical example of a build-up curve and two field examples of drill stem tests. Introduction A need has existed for an accurate method of determining the distance from a well bore to a discontinuity. Many advantages will be afforded the well owner if he can determine the distance to a discontinuity. For, example, a much higher permeability section may be indicated at some distance from permeability section may be indicated at some distance from the well bore as shown in Figure 1. Calculating the distance to the higher permeability section will provide the answer as to whether or not the section can be reached with a stimulation treatment such as hydraulic fracturing. Also, assume a test of a water bearing section indicates a gas-water contact as shown in Figure 2. The distance to the contact will determine whether a new well must be drilled higher on the structure or whether a side track from the original hole is feasible for penetrating the formation above the gas-water contact. Additional examples of common discontinuities are shown in Figures 3 and 4. One of the prime objectives of a drill stem test is to determine the flow capacity of the zone being tested. The flow capacity is directly related to the transmissibility of the formation which is directly related to the effective reservoir permeability and effective formation thickness, and inversely permeability and effective formation thickness, and inversely proportional to the viscosity of the flowing fluids. The flow proportional to the viscosity of the flowing fluids. The flow capacity is further affected by the amount of well bore damage present. present. Drill stem tests are usually comprised of a sequence of flow periods followed by shut-in periods. The shut-in periods (build-up curves) provide the basic data which is utilized in calculating values for transmissibility and well bore damage. BASIC INTERPRETATION Homogeneous Reservoir Transmissibility is obtained from a plot of the build-upT + 0 pressure versus the log ----- as shown in Figure 5. pressure versus the log ----- as shown in Figure 5. 0 Theoretically, the points will fall on a straight line with a slope of m psi/cycle. Extrapolation of that straight line to T + 0 ------ = 1 gives the static reservoir pressure. The 0 transmissibility is obtained from the relationship: Kh 162.6qB----- = ---------m Where K = effective permeability in md. h = effective formation thickness in ft. = flowing fluid viscosity in cp. M = slope of the build-up curve in psi/cycle. B = formation volume factor. q = flow rate prior to shut-in, bbls/day.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, October 4–7, 1970

Paper Number: SPE-3067-MS

... solution for an infinite reservoir was obtained numerically and used for pressure drawdown and buildup analysis. The pressure drawdown and buildup analysis. The numerical results shows that: On pressure drawdown and

**buildup****curves**, two straight lines are obtained; the first straight line with lower slope...
Abstract

American Institute of Mining, Metallurgical and Petroleum Engineers Inc. This paper was prepared for the 45th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct 4–7, 1970. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract A simulation model of a reservoir with a symmetrical-horizontal fracture extending from the wellbore to the midpoint of the drainage radius was constructed. The mathematical equation was developed for the case of single-phase unsteady state fluid flow. A solution for an infinite reservoir was obtained numerically and used for pressure drawdown and buildup analysis. The pressure drawdown and buildup analysis. The numerical results shows that: On pressure drawdown and buildup curves, two straight lines are obtained; the first straight line with lower slope yields the effective permeability of the matrix and fracture, and the second straight line with greater slope yields the permeability of matrix. The time of bend between the straight lines increases with increase in fracture radius. As the fracture radius approaches infinity, only one straight line of the Odeh type is obtained. Extrapolation of the first straight line portion of the buildup curve may lead to an incorrect value of the static reservoir pressure. pressure Introduction Analysis of pressure buildup and drawdown data is recognized as a powerful tool by the production and reservoir engineer seeking to production and reservoir engineer seeking to characterize the reservoir. Most pressure analysis techniques have assumed homogeneous reservoirs, i.e. the porosity and permeability are constant. However, some prolific wells produce from fractured reservoirs. These produce from fractured reservoirs. These reservoirs contain two distinct types of porosity and permeability, namely fracture porosity and permeability, namely fracture and matrix. Since the fractured region has higher permeability, reservoir-engineering analysis based on a homogeneous reservoir may lead to erroneous results. The purpose of this study is to develop a mathematical model which will simulate the pressure drawdown and buildup curves that would be obtained from a reservoir with a symmetrical-horizontal fracture around the wellbore. The mathematical model is developed by assuming a cylindrical reservoir of drainage area of uniform thickness is penetrated by a single production well at its center. The two -dimensional diffusivity equation for single phase flow was used to obtain pressure buildup phase flow was used to obtain pressure buildup and drawdown curves. It was necessary to obtain a constant rate solution to the equation because of the mathematical complexities introduced by the fractured reservoir geometry.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, October 1–4, 1967

Paper Number: SPE-1820-MS

... finite conductivity. This work thus extends the work of Russell, who analyzed the transient behavior of vertically fractured wells by assumin the fracture to have infinite conduc- tivity.? The attack in both this study and in Russell s investigationwas the same: synthetic

**buildup****curves**were developed on...
Abstract

American Institute of Mining, Metallurgical and Petroleum Engineers, Inc. This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Methods for analyzing fractured reservoirs by using transient pressure tests have been developed to help characterize these format These techniques permit estimating fracture length and conductivity in formations with either vertical or horizontal fractures, estimating reservoir pressure and permeability in fractured wells. Finite conductivity fractures are considered in this analysis, whereas previous work has been reported only for fractures with infinite conductivity. Pressure buildup tests may be used for estimating fracture length and fracture conductivity in formations with either horizontal or vertical fractures. These estimates should be useful for evaluating fracture treatments. The estimates are made by comparing observed buildup test behavior to calculated behavior for idealized reservoir models. Techniques for analyzing pressure buildup tests are suggested to estimate formation permeability and static reservoir pressure. In many fractured wells, conventional procedures for making these estimates are not applicable hence, the suggested methods. Introduction Technology for interpreting well tests in fractured reservoirs has been nonexistent until the recent past although large numbers of wells are fractured each year. It has not been possible to estimate formation permeability or static reservoir pressure correctly in many fractured wells, nor has it been possible to estimate fracture length and conductivity, which would aid in evaluating fracturing methods. The purpose of this study was to help fill this gap in technology by developing methods of analyzing horizontal and vertical fractures of finite conductivity. This work thus extends the work of Russell, who analyzed the transient behavior of vertically fractured wells by assuming the fracture to have infinite conductivity. The attack in both this study and in Russell's investigation was the same: synthetic buildup curves were developed on a computer for ideal reservoir models, and analysis techniques were developed from these curves. In essence, these techniques involve comparing observed transient pressure data with computed data, and finding the model [i.e., the fracture length and conductivity] which best fits the observed data.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, August 10–October 11, 1961

Paper Number: SPE-144-MS

Abstract

PUBLICATION RIGHTS RESERVED This paper is to be presented at the 36th Annual Fall Meeting of the Society of Petroleum Engineers of AIME in Dallas October 8–11, 1961, and is considered the property of the Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of JOURNAL OF PETROLEUM TECHNOLOGY or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in JOURNAL OF PETROLEUM TECHNOLOGY or SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted on request, providing proper credit is given that publication and the original presentation of the paper. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper. Abstract The stabilization factor can be defined as the ratio of a well's performance under psuedo-steady state conditions to the well's performance at the end of a given length of flowing time. For the purposes of using pressure build-up analyses in the Hugoton Field, it has been convenient to use the ratio of pressure build-up at the end of 72 hours compared to the maximum pressure build-up. In highly permeable reservoirs, the stabilization factor is approximately unity, but in the tighter, lower permeability reservoirs it can decrease to 0.25 or even lower values. In general, stabilization can be considered an unsteady-state or transient flow phenomena. Therefore, it should be studied using the mathematical analyses developed for this type of flow. Most of the theoretical work has been completed by previous workers and the present study is mainly one of applying their work to field data, and very little new theory is introduced. The data for this study is surface recorded information on a large number of wells in the Hugoton Fields of Kansas, Oklahoma and Texas. The results of analyzing surface pressure buildup information are compared with results of analyzing flow tests on the same wells, and from these analyses an attempt is made to predict the expected future performance of Hugoton Field gas wells. The study concludes that the analyses of the pressure buildup data will accurately reflect the conditions necessary to predict stabilization factors for use in availability studies, that the analyses of flow data which is more difficult and expensive to obtain can often lead to erroneous conclusions, and a reasonable comparison between flow and build-up data can be realized if sufficient care is used in collecting and analyzing the basic data. Introduction Without an accurate knowledge of stabilization factors and other formation characteristics, future planning of operating facilities, future availabilities of gas, and future gas contracting requirements become difficult to anticipate.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, October 4–7, 1959

Paper Number: SPE-1333-G

... for this calculation includes the change in pressure interference, slope of the

**buildup****curves**, average fluid compressibility, well locations, and production histories of all wells. An analysis was made of the error in porosity-thickness product resulting from errors in pressure measurements and other...
Abstract

Abstract The purpose of this paper is to present the results of a theoretical study of the effect of interwell interference on pressure buildup in a shut-in well in multi-well reservoirs. An equation was developed which describes pressure buildup in a homogeneous, infinite reservoir of uniform thickness containing a single, mobile fluid which is slightly compressible. Using this equation, the pressure buildup in a shut-in well in a reservoir containing a number of offset producing wells was calculated on an electronic digital computer. For this study the offset wells had specified,, variable production rates. These computations illustrate the nature of pressure interference during pressure buildup tests. The study shows that offset producing wells can cause appreciable pressure drawdown at a shut-in well. The existence of interference does not obviate the use of the conventional Horner technique for estimating permeability and static well pressure from pressure buildup tests. A method is derived for calculating the average porosity-thickness product for a reservoir from a change in pressure interference which is induced by altering production rates of offset wells. Information required for this calculation includes the change in pressure interference, slope of the buildup curves, average fluid compressibility, well locations, and production histories of all wells. An analysis was made of the error in porosity-thickness product resulting from errors in pressure measurements and other factors required in the calculations. Introduction Pressure buildup tests have been used for a number of years to determine the static bottom-hole well pressure. More recently, these tests have also been used the average reservoir permeability in the drainage area of the shut-in well. Perhaps the most widely used method for interpreting pressure buildup data to obtain the static pressure and average permeability is the one proposed by Horner, based on the theoretical analysis of pressure buildup in a single well in an infinite reservoir.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Fall Meeting of the Petroleum Branch of AIME, October 3–5, 1951

Paper Number: SPE-123-G

... pressure decline data Error gauge data quality accuracy pressure measurement cent error Upstream Oil & Gas calculation psi gauge water drive

**buildup****curve**Magnitude Reservoir Engineering Calculation equation permeability field drillstem/well testing pressure decline quantity error...
Abstract

Abstract In reservoir analysis important quantities such as reservoir pressure, in-place oil, and well damage are calculated from directly measured quantities and each measurement error has an effect on the calculated result. This paper employs statistical methods in the quantitative consideration of the effect of these measurement errors on answers calculated by specific formulas which may be taken as typical of reservoir engineering calculations. Detailed studies have been made concerning reservoir pressure, reservoir pressure decline, initial in-place gas in distillate fields, initial in-place oil in unsaturated fields, initial in-place oil in solution gas drive fields, and well damage. A wide range of examples is presented so that the conclusions may be generally applicable. Various intangible factors which cannot be included in the equations limit the quantitative applicability of the calculated error, but these factors reinforce rather than detract from the conclusions. Particular attention is given to the effect of bottom hole pressure measurements errors. The overall conclusion from this study is that in nearly all cases the errors in bottom hole pressure measurements make the major error in reservoir engineering calculations and that in many instances an increased accuracy of the pressure instruments to ±1 psi is highly desirable. Introduction The question of what accuracy is required in the data assembled for the purpose of making reservoir analyses has been the subject of much discussion in the past. Extremes of opinion have been encountered, ranging from a belief that reservoir analysis is approximate at best and that very approximate data are sufficient to an insistence that all factors be measured to the utmost possible precision.