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Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production and Operations Symposium, March 23–26, 2013

Paper Number: SPE-164483-MS

... ways to

**determine**or estimate the S or , these includes: ■ Laboratory Methods: ○ Core Analyses, ○ Core Flooding, ○ Centrifuge, ○ Counter-Current Imbibition (CCI), ○ Digital Rock Physics (DRP). ■ Field Methods: ○ Well log analyses, ○ Well tracer tests...
Abstract

In petroleum reservoirs only a small fraction of the original oil-in-place is economically recovered by primary, secondary, and tertiary recovery mechanisms. A considerable amount of hydrocarbon ends up unrecovered or trapped due to microscopic phase trapping in porous media which results in an oil recovery factor typically less than 50%. Waterflooding is by far the most widely used method to increase oil recovery. The oil that remains in the porous media after waterflooding is called remaining oil saturation (ROS) which is larger than the relative permeability residual oil saturation ( S orw or simply S or ). This residual oil saturation varies depending on lithology, pore size distribution, permeability, wettability, fluid characteristics, recovery method, and production scheme. Determination of the residual oil saturation of a reservoir is a key parameter for reserve assessment and recovery estimates. Further, reliable S or data is important for investigation of possible incremental recovery under Enhanced Oil Recovery (EOR) methods. Various residual oil saturation measurment techniques are available both at laboratory and field scale. None of the techniques can be regarded as a single best method of determining S or . Depending on the complexity of the reservoir under study, combinations of methods are always advisable for appropriate S or determination. This study is an up-to-date review of techniques used in determining S or in laboratory and field. The study further reports on the advantages and limitations of each method and provides recommendations for best practices.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Production and Operations Symposium, March 31–April 3, 2007

Paper Number: SPE-105928-MS

... by means of the TDS technique8, and a methodology using the conventional analysis is matter of this article, since this technique is widely accepted by most of engineers. A procedure is also presented for the

**determination**of the horizontal permeability anisotropy, using the linear plot of pressure...
Abstract

Abstract Besides the regular four flow regimes normally seen during a pressure test of horizontal wells, it is possible, under special circumstances, to observe such additional flow regimes as spherical, hemi-radial, linear (reservoir channel) and elliptical. The last flow regime is characterized by a slope of 0.36 of the pressure derivative curve and occurs between the early linear flow and the pseudo-radial flow periods. This may have been overlooked in horizontal well test analysis, because it is often masked by the other flow regimes, unless the conditions are just right. The elliptical flow regime has been previously mentioned by very few researchers5–7. A methodology for its characterization has been also introduced using the pressure derivative concept and TDS technique7. However, conventional analysis for the characterization of this has not yet been reported in the literature. This flow regime is very useful to estimate the horizontal permeability, especially, when the pseudo-radial flow is very short or unclear, or simply, when it is desired to verify this estimation. In this paper, equations for the estimation of the horizontal permeability and elliptical skin factor are developed for both gas and oil horizontal wells, so that the mentioned parameters can be estimated, respectively, from the slope and intercept of linear plot of pressure versus time to the power 0.36. The equations were successfully tested with two field examples previously worked in the literature. 1. Introduction Horizontal wells have proved to provide better productivity index than vertical wells. This fact made them very attractive to the oil industry around the world. Therefore, an appropriate identification and evaluation of the well pressure models is very encouraged. Several great contributions to the field of horizontal well test analysis are reported in Refs. 1 through 4. However, recently, Isaaka et al.5 and Chacon et al.6 introduced the concept of elliptical flow as sketched in Fig. 1. Escobar et al.7 presented a methodology for the characterization of this flow regime by means of the TDS technique8, and a methodology using the conventional analysis is matter of this article, since this technique is widely accepted by most of engineers. A procedure is also presented for the determination of the horizontal permeability anisotropy, using the linear plot of pressure (or pressure drop) against time to the power 0.36. The application of this procedure is demonstrated on field data of two horizontal well tests previously presented in the literature.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production Operations Symposium, April 16–19, 2005

Paper Number: SPE-94266-MS

... this type of completion.The liquid holdup of the multiphase flow in the well is

**determined**from the Inelastic Ratio measurements of a Pulsed Neutron log and the annular water velocity is directly obtained from the analysis of water flow measurements in the annulus of the well. Introduction The...
Abstract

Abstract This paper addresses the development and validation of a production logging analysis methodology and associated formation inflow interpretation model for wells that have their production tubing string setting depth below the top of at least the shallowest completed interval in the well.This type of completion technique is commonly utilized in wells that produce formation liquids and in which the tubing is lowered in the well below the top of the shallowest(and possibly additional deeper) completed interval(s) in order to assist in unloading the well of the produced liquids.When this is done, conventional production logging tools and techniques can not be used to measure the inflow profile of the completed intervals that are shallower than the tubing setting depth in the well without raising the tubing above the shallowest completed interval, which can alter the inflow profile of the well. This paper specifically considers the development of a reliable means of performing an equivalent inflow performance analysis, analogous to that which would be obtained with conventional production logging analyses if those inflow profile evaluation techniques could be used in wells with this type of completion.The liquid holdup of the multiphase flow in the well is determined from the Inelastic Ratio measurements of a Pulsed Neutron log and the annular water velocity is directly obtained from the analysis of water flow measurements in the annulus of the well. Introduction The inflow performance of multilayer reservoirs that have been completed and produce into a single well bore in a commingled system is commonly obtained using production logging techniques.The inflow from each of the completed intervals in the well is commonly computed from the measurements of the well fluid flow rate using a spinner type flow meter device, in combination with various other measurement probes to record the well bore fluid mixture density, pressure, temperature, and also recently the fractions of the well stream fluid that is comprised of gas and liquid using optical scanning devices.In a well completion in which the conventional production logging devices can be employed to record the flow, pressure, temperature, and fluid mixture density in the well past each of the completed intervals, the direct measurement of these parameters permits the evaluation of the inflow from each of the completed intervals in the well.However, in well completion scenarios in which the production tubing string has been run into the well to a setting depth greater than the depth of one or more of the completed intervals in the well, the direct evaluation of the individual completed interval inflow contributions to the composite system production using conventional production logging devices is not practical. One common reason for having a production tubing string setting depth greater than the depth to the top of the shallowest completed interval in the well is that of unloading the well of produced formation fluids.This concept also applies to the design and use of velocity strings in producing wells that reach the point of "loading up" with liquids.In these cases, the tubing string commonly extends into the well to a depth greater than the depth to the top of the shallowest completed interval.When the tubing setting depth is greater than the depth of the shallowest completed interval in the well, the direct measurement of the well fluid flow rate for the completed intervals that are shallower than the end of the tubing string can not be directly measured using a spinner type device. It is for these types of well configurations that an alternative fluid flow measurement device must be employed.One readily available measurement device and interpretation methodology than can be used to evaluate the fluid velocity (even in the annulus of the well) is the Pulsed Neutron log[1,2].The only two requirements for the use of this type of fluid flow measurement device is that (1) there is at least a small quantity of water present in the flow stream of the fluids for which the fluid velocity is to be determined, and (2) that the proper spacing of the Pulsed Neutron logging device receivers in relation to the source are commensurate with the fluid velocity to be recorded.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production and Operations Symposium, March 23–25, 2003

Paper Number: SPE-80936-MS

... interpretations are not always straightforward and can lead in some practical applications to the failure of propant placement i.e : a screen out with an impact on the post frac well's productivity. In this paper a new interpretation technique for closure pressure

**determination**is presented. It is based on a...
Abstract

Abstract Hydraulic fracturing design is highly dependent on the knowledge of the injection fluid efficiency. This parameter is generally derived from the interpretation of the calibration tests fall offs. Two popular methods are the square root of time and Nolte's G function 1,2,3,4 . Such interpretations are not always straightforward and can lead in some practical applications to the failure of propant placement i.e : a screen out with an impact on the post frac well's productivity. In this paper a new interpretation technique for closure pressure determination is presented. It is based on a novel utilisation of Nolte's F function 5 . Field cases on Algeria's In-Adaoui field are analysed. Proppant placement failures are explained. These examples demonstrate the usefulness of the F function for improving hydraulic fracturing design whether for a conventional permeabilty estimation or for closure pressure and hence efficiency determination. Introduction It is a conventional method to perform a calibration test before a Hydraulic fracturing job. The main objectives are an assessment of fracture as well as fluids and rock geomechanical properties. Volumes ranging from a few barrels to more than a 1000 barrels 6 are pumped at the forthcoming hydraulic fracturing job rate. Generally the same fluids are used during the calibration tests and the main treatment. The information that is commonly sought after can be as simple as the injectivity and pressure levels and as detailed as the generated fracture geometry 7,8,9 . Most often a calibration test is used as a means of optimising the main job design by better estimating fracturing fluids leak off characteristics. Fracture closure pressure and subsequent fluid efficiency are derived from fracturing pressure decline analysis using Nolte's G function or square root of time plot. Recently, Nolte et al 5 added the after closure period analysis to the fracture calibration test pressure interpretation to achieve the optimum fracture design. Such analysis consists on using the F function time to determine reservoir transmissibility and pressure. Background of After-Closure Analysis of Fracture Calibration Tests Fall off interpretations generally end after pinpointing the fracture closure. The next operation is the proppant frac itself and at this step no time is lost to proceed with designing and pumping the main job in order to save mobilisation and production time. However, The pressure transient is still in progress since closure pressure is higher than reservoir pressure. Given that the fracture is already closed then the pressure behaviour depends solely on the formation transmissibility and the fracturing fluid properties. Nolte et al 5 studied the after closure period and presented an analysis that allows the determination of two important parameters from the after closure : the transmissibility of the formation and the reservoir pressure. This effort was fully justified considering that in several instances key data for fracturing design such as permeability is not available for lack and difficulty of data collection such as a build up test in a tight formation or simply for the fact that the candidate well has not produced before the job. The after closure period of a calibration test could contain the reservoir pseudo linear flow and pseudo radial flow. The after closure pseudo-linear flow analysis is from Carslaw and Jaegar's heat transfer analysis 10 . Nolte suggested that for heat transfer and reservoir behavior temperature and pressure are analogous therefore the pressure response could be expressed by: Equation 1 For the after closure pseudo-radial flow analysis is from the impulse test test interpretation 11 . For that, Nolte et al 5,12 have developed a combined method, using numerical simulation, to apply it for the after closure period of fracture calibration tests in order to identify flow regimes and determine reservoir parameters. They developed an apparent time F function.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production and Operations
Symposium, March 24–27, 2001

Paper Number: SPE-67241-MS

... pressure. Only records of the flowing time and cumulative production data are required to compute the value of the skin factor. A semi theoretical equation is used to approximate the dimensionless flow rate. This formula is used to obtain a quadratic equation for

**determining**the skin factor. The...
Abstract

Abstract A new technique has been developed for analyzing the constant bottomhole pressure (BHP) test data. The method presented in this note allows to calculate the skin factor for damaged and stimulated oil wells. Advantages of the BHP test are: they do not require that well be shut in; the fluid production can be easily controlled (at constant flow rate tests the BHP is changing with time); and wellbore storage effects on the test data are short-lived. It is assumed that the instantaneous flow rate and time data are available from a well produced against a constant bottomhole pressure. Only records of the flowing time and cumulative production data are required to compute the value of the skin factor. A semi theoretical equation is used to approximate the dimensionless flow rate. This formula is used to obtain a quadratic equation for determining the skin factor. The accuracy of the basic equation will be shown below. The paper includes an example o calculation. Dimensionless Flow Rate Let us assume that the well is producing against a constant bottomhole pressure from an infinite-acting reservoir and the effective wellbore radius concept can be used 1 . In this case the relationship between well flow rate and time for a well with a constant BHP in oil field units is 2 Equation (1) Equation (2) Equation (3) Where q D is dimensionless flow rate, and t D is the dimensionless time based on the apparent well bore radius (r wa ) concept. We should also to note that Equation 1 is widely used in petroleum industry to forecast oil flow rates. Analytical expressions for the function q D =f (t D ) are available only for asymptotic cases or for large values of t D 3,4 . The dimensionless flow rate was first calculated (in tabulated form) by Jacob and Lohman 3 . Sengul 5 computed values of q D (t D ) for a wider range of t D and with more table entries. We have found 6,7 that for any values of dimensionless production time a semi theoretical Equation 4 can be used to forecast the flow rate Equation (4) Equation (5) Equation (6) In the Table 1 values of q D * calculated after Equation 4 and the results of a numerical solution 5 (q D *) are compared. The agreement between values of q D and q D * calculated by these two methods is seen to be good.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production and Operations
Symposium, March 24–27, 2001

Paper Number: SPE-67318-MS

... Abstract Direct interpretation methods for

**determination**of the relative permeability data by linear, non-steady-state, two-phase fluid displacements conducted via constant rate and constant pressure laboratory core tests, are presented. The equations necessary for processing of the...
Abstract

Abstract Direct interpretation methods for determination of the relative permeability data by linear, non-steady-state, two-phase fluid displacements conducted via constant rate and constant pressure laboratory core tests, are presented. The equations necessary for processing of the displacement test data obtained after the breakthrough of the displacing fluid phase are derived by neglecting the capillary end-effects at sufficiently high flow rates and verified by various experimental data. The total mobility and the mobility ratio of the immiscible fluids are related to the characteristic parameters of the displacement process and the cumulative injected fluid pore volume. The general correlation functions of the characteristic parameters of the immiscible displacement process in porous media are facilitated to conveniently describe the relative permeability functions. These functions allow for accurate determination of the characteristic parameters of immiscible displacement by least-squares linear regression of experimental data. Therefore, the present analytic method determines the relative permeability functions uniquely, rapidly, and more accurately than the previous direct interpretation methods, auxiliary functions, and graphical and analytical methods, and offers a possibility of determining the relative permeability functions from constant pressure and constant rate displacements data. Introduction Relative permeability is an essential petrophysical data required for characterization of multiphase flow in petroleum reservoirs. Frequently, the relative permeability data of the two-phase flow in porous media is determined by interpreting the data of the laboratory displacement tests carried out with cylindrical core plugs extracted from petroleum reservoirs. The Darcy law and the material balance equations, with appropriate initial and boundary conditions, are applied to describe the flow of the various fluid phases in porous media. This theoretical description of flow is used to infer for the relative permeability data by processing of the experimental data using a suitable method. This is an inverse problem and development of better methods for its solution has occupied many researchers. Especially, the achievement of the uniqueness in the calculated relative permeability data is of a great concern. In this respect, direct interpretation methods are favored over the indirect regression or matching methods. Honarpour et al. 1 give a comprehensive review of the experimental methods for determination of the values of relative permeability. In general, two basic laboratory methods have been facilitated by the petroleum industry: the steady-state method, where both fluids, usually considered incompressible, are injected simultaneously into the core, and the non-steady-state method, where only one fluid is injected into the core to displace another fluid present in a core plug. The processing of the steady-state test data is relatively simple, but the experiments are tedious, because attaining a steady average saturation value over the core length after each saturation alteration requires a long time, typically several hours. On the other hand, the laboratory tests of the non-steady-state displacements at different flow conditions can be performed within a relatively short time, but the evaluation of the data is a complex task. In both methods of measurements, the unfavorable capillary end-effects, appearing at the inlet and outlet faces of the core plug, further complicate the processing of the experimental data, unless the displacement can be carried out at a sufficiently high rate to minimize the end-effects. However, a rapid flow is usually difficult to accomplish in core plugs and does not represent the actual flow conditions in typical reservoir displacements. Nevertheless, the end-effects are often neglected for development of simplified interpretation methods.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Mid-Continent Operations Symposium, March 28–31, 1999

Paper Number: SPE-52220-MS

... analysis fracture length injection fracture swindell pressure decline drillstem testing closure time

**determination**reservoir pressure hydraulic fracturing application closure pressure interpretation linear-flow analysis Copyright 1999, Society of Petroleum Engineers Inc. This paper was...
Abstract

This paper was prepared for presentation at the 1999 SPE Mid-Continent Operations Symposium held in Oklahoma City, Oklahoma, 28-31 March 1999.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production Operations Symposium, March 9–11, 1997

Paper Number: SPE-37410-MS

...

**determination**viscosity ikoku drilling fluid chemistry average formation pressure composite formation drilling fluid property homogeneous formation drilling fluids and materials penneability Society of Petroleum Engineers SPE 37410 A Simple Method for**Determination**of Radius of Investigation for Non...
Abstract

Abstract Transient pressure testing is an important tool in obtaining reservoir information. Information derived from transient tests is useful only to those portions of the reservoir in which flow has occurred during the test. Thus, determination of radius of investigation (ROI) is essential. The most commonly used ROI equations were derived for Newtonian fluids Darcy flow in a homogeneous formation. Limited information of ROI is available for systems involved with non-Newtonian fluids or non-Darcy flow which could be important in polymer flooding or production of gas wells. ROI was determined in this paper by combining material balance equation and pressure distribution at any given testing time. This method of determining ROI was applied to non-Newtonian power-law fluids Darcy flow and Newtonian fluids non-Darcy flow in both homogeneous and composite formations. Main observations from this study included that for non-Newtonian power-law fluids: ROI was compared with a literature ROI model which is applicable in the range of 0< n <1. Within {0,1}, the two models give consistent results with the difference being zero at about n =0.6. The applicable range for the new model however is n 0 9. When n <1, ROI increases with flow rate, q , while n >1, ROI decreases with increase in q . At n =1, ROI is independent on q . Difference between original formation permeability, k , and the permeability around wellbore, k A , has a significant effect on ROI if k A / k <1. The effect of k A / k on ROI increases with n, k A / k has minor effect on ROI if k A / k >1. For Newtonian fluids non-Darcy flow, ROI is dependent on flow rate, ROI is less than that for Darcy flow, and ROI decreases with increase in turbulent factor. Introduction Radius of investigation (ROI) is used to estimate the time required to test the desired area in a formation. The most commonly used radius of investigation, r i , was obtained by van Poollen, 1 r i,P , by assuming that a Newtonian fluid flows in a uniform, homogeneous, and isotropic formation under the conditions of Darcy flow. (This is referred as ideal systems.) Equation 1 where k is the formation permeability, f porosity, µ Newtonian fluid viscosity, C t total compressibility, t testing time, and E 1 is a unit conversion factor. A detailed review and discussion of Eq. 1 was given by Johnson. 2 Consistent units should be used in Eq. 1 and all the following equations in this study. However, direct application of these equations could be difficult. Therefore a unit conversion factor, E, is included for the more convenient field units. If the parameters in Eq. 1 have the units as shown in Table 1, E 1 is equal to 0.016238. Numerous pressure transient studies for non-Newtonian fluids 3–6 and high flow rate non-Darcy flow 7–9 have been reported. However, limited information on ROI was available for systems involved with (1) non-Newtonian fluids, (2) non-Darcy flow, and (3) non-homogeneous porous media.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production Operations Symposium, April 2–4, 1995

Paper Number: SPE-29502-MS

... length of the hydraulic fracture contributing to unrestricted production. It is

**determined**that the performance of a hydraulically fractured vertical well with mechanical skin and fracture half length x, can be substituted by the performance of a fractured half-length xf2 with no skin. New equations...
Abstract

Abstract This paper presents a new technique for analyzing the performance of hydraulically fractured vertical wells in bounded reservoirs. The main objective is to present a new set of practical equations, based on the recently introduced concepts in well testing, for evaluating the effective length of the hydraulic fracture contributing to unrestricted production. It is determined that the performance of a hydraulically fractured vertical well with mechanical skin and fracture half length x, can be substituted by the performance of a fractured half-length xf2 with no skin. New equations presented in this paper can be used to determine pseudo skin factor, effective fracture half-length, mechanical skin factor. shape factor, and productivity index of fractured vertical wells. The new equations and guidelines given in this paper can be used to determine the magnitude of formation damage around hydraulically fractured vertical wells and to evaluate the success of the stimulation treatment. An example based on simulated well test data is presented to illustrate the application of the new technique. The problems associated with the use of the finite-conductivity fracture model are discussed and it is recommended that the pressure transient data obtained on fractured vertical wells be analyzed with effective hydraulic fracture length concept. in preference to the finite-conductivity fracture model. Introduction Hydraulic fracturing plays an important role in increasing the productivity of a damaged well or wells producing from low permeability formations. At the present time, 35 to 40% of all vertical wells drilled are hydraulically fractured and 23 to 30% of total US oil reserve have been exploited by thIs technique. The net increase in the oil reserve for North America as a result of hydraulic fracturing is believed to be about 8 billion barrels. A hydraulic fracturing treatment should be designed based on reservoir properties, the economics of the well, well spacing, desired propped fracture length and desired productivity index increase (which depends on the areal extent of the fracture). In addition to mechanical properties of the rock, proppant concentration, viscosity and injection rate of the fracturing fluid, the leakoff of the fracturing fluid into the formation is also an important factor affecting the volume (or size) of the induced hydraulic fracture. Hydraulic fracturing models that predicts the width, length, and height of the created fracture had been developed that takes into account the above mentioned parameters. Pressure transient analysis of hydraulically fractured wells can be used to evaluate the performance of these wells. During the last three decades extensive studies have been done to determine the fracture characteristics and formation properties using pressure transient analysis. These studies made it possible to analyze the entire pressure history of a well test, not just late time data as in conventional analysis. P. 557

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production Operations Symposium, March 21–23, 1993

Paper Number: SPE-25425-MS

...Society of Petroleum Engineers SPE 25425 Formation Permeability

**Determination**Using Impulse-Fracture Injection Hongren Gu, J.L. Elbel, and K.G. Nolte, Dowell Schlumberger; A.H-D. Cheng, U. of Delaware; and Younane Abousleiman, U. of Oklahoma SPE Members Copyright 1993, Society of Petroleum...
Abstract

SPE Members Abstract "Impulse fracture" is an injection test used to determine formation permeability and reservoir pressure. The test consists of a small-volume water injection to create a short fracture and a shut-in period afterwards to record pressure falloff. The pressure falloff after fracture closure is used to deduce permeability and reservoir pressure. The fracture can pass the near-wellbore damaged area and have the true formation exposed to flow transients. Also, fracturing may sometimes be difficult to avoid for injections in low-permeability formations. The theory and analysis of impulse fracture are based on an instantaneous- source solution to the diffusivity equation. Numerical simulation examples and field case studies are used to support the validity of the analysis. The applicability of impulse fracture in gas reservoirs is demonstrated by numerical simulation results from a multi-fluid-bank simulator and by field cases. The impulse-fracture injection test is an economical and simple means to determine formation permeability. The test can be conducted in conjunction with mini-fracture or micro-fracture stress-test injections. Introduction "Impulse fracture" is an injection test for determination of formation permeability and reservoir pressure. It consists of an injection and a shut-in period. During the injection, a small volume of water is injected into the well, and a short fracture is created in the formation. During the shut-in period, the pressure falls off and the fracture closes. The pressure is recorded before and after the fracture closure. The late-time pressure-falloff data, after the fracture closure, is used to deduce permeability and reservoir pressure. The impulse-fracture injection test is similar to the slug test or the impulse test. In a slug test, a small volume of fluid is injected into, or withdrawn from, the reservoir to create a pressure disturbance in the formation. The subsequent pressure response is analyzed to estimate the reservoir flow properties. As a simple and economical means of evaluating reservoir properties, the slug test has many applications in the petroleum industry. Like the slug test, the theory and analysis of the impulse-fracture test are based on an instantaneous-source solution to the diffusivity equation. When the duration of the injection period is short compared with the shut- in time, the injection can be considered as an instantaneous source. The flow regime of the test can be identified based on the characteristics of the instantaneous-source solution, and the reservoir parameters can be deduced. P. 189^

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production Operations Symposium, March 21–23, 1993

Paper Number: SPE-25466-MS

...Soclety of Petroleum Engineers SPE 25466

**Determination**of Hydraulic Fracture Direction, San Juan Basin, New Mexico D.P. Yale, M.K. Strubhar, and A.W. EI Rabaa, Mobil R&D Corp. SPE Members Copyright 1993, Society of Petroleum Engineers, Inc. This paper was prepared for presentation at the Production...
Abstract

Abstract Reservoir management of hydraulically fractured reservoirs can be improved with knowledge of the orientation of hydraulic fractures. Fracture direction can affect where wells are placed, the design of well patterns for EOR floods, the design of fracture treatments, and the stability and fracturing of horizontal wells. This paper presents a field study of the determination of hydraulic fracture direction in the San Juan basin in northwest New Mexico. Data from six different fracture direction techniques were integrated to improve the determination of fracture direction. Integrating results from the six techniques not only improves the accuracy of the results but also allows us to compare the techniques to one another on the basis of reliability of results, operational requirements, and cost effectiveness. The average of all the data from each of the four wells suggests a hydraulic fracture direction of 41 azimuth in this area of northwest New Mexico. The trends agree with regional in-situ stress direction for the areal. There were only small variations between wells and the fracture direction was consistent with depth over the 300 feet of formation tested. The direction of natural fractures as seen in the core and in the borehole televiewer was similar to the hydraulic fracture direction. Based on this study and other published reports on hydraulic fracture/in-situ stress direction, we believe hydraulic fracture direction is best determined by integrating results from multiple techniques in several wells in an area. We find that the ability to determine fracture direction is most affected by the horizontal stress contrast in the area and the presence of paleo-imprints on the rocks. Fracture direction can strongly affect the recovery of hydrocarbons from hydraulically fractured fields and should be a datum that is collected routinely in the development of such fields. Introduction Because hydraulic stimulation fractures open normal to the least principal stress, most fractures are vertical and propagate in the direction of the maximum horizontal in-situ stress. This direction therefore influences the design of hydraulic fracture treatments, the drainage patterns around fractured wellbores, and the stability of horizontal or highly deviated wells. Knowledge of the direction of the in-situ stress is therefore important for optimal drilling, effective well completions, and efficient reservoir management. The drainage pattern around fractured wells is highly anisotropic (see Figure 1). In-fill drilling is done to access undrained portions of the reservoir. However, in-fill wells placed without regard to fracture direction can result in overlapping drainage areas and leave large areas of the reservoir undrained. Reservoir performance can be optimized by accounting for fracture direction in the placement of infill wells (see Figure 1). Premature water or steam breakthrough during EOR floods can be due to fluid movement along fractures from an injector to a producer (see Figure 2a). Characterizing the orientation of stress in the reservoir can help forestall premature breakthrough and enhance sweep efficiency by allowing injector/producer patterns to be optimized for sweep efficiency as shown in Figure 2b. Wellbore stability in horizontal or highly deviated wells is enhanced by drilling the well parallel to the minimum horizontal stress direction. This allows the widest margin in mud weights between well collapse due to underbalanced drilling and well fracturing due to overbalanced drilling. Horizontal well stimulations also are controlled by the direction of the maximum horizontal stress. If several transverse fractures need to be created in the wellbore, the horizontal well must be drilled parallel to the minimum horizontal stress direction. P. 543^

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production Operations Symposium, April 7–9, 1991

Paper Number: SPE-21661-MS

... Abstract The

**determination**of reservoir porosity through casing has become a vital concern as more old fields undergo detailed re-evaluation. Many times the prevailing situation is that there Is no reliable porosity data and the well has tubing in place. in porosity data and the well has...
Abstract

Abstract The determination of reservoir porosity through casing has become a vital concern as more old fields undergo detailed re-evaluation. Many times the prevailing situation is that there Is no reliable porosity data and the well has tubing in place. in porosity data and the well has tubing in place. in such cases, pulsed neutron capture (PNC) logs are often relied on for both formation porosity and capture cross-section information. Environmental effects on the pulsed neutron count rate ratio curve can be quite large and can have a dramatic effect on porosity calculations. This paper discusses the empirical modeling of typical downhole conditions that affect the TMD* ratio log and Introduces updated corrections that can be applied to compensate for them. Included In the modeling are effects due to varying borehole fluid salinity, casing and tubing diameter, and cement. A lithology dependent ratio porosity transform makes this conversion more porosity transform makes this conversion more consistent with density, neutron and acoustic techniques. When wellbore conditions are known, these computations can be applied either real-time or post-log at the wellsite to allow Immediate reservoir evaluation. Both test formation and field log data are presented to demonstrate the accuracy and utility presented to demonstrate the accuracy and utility of the environmental corrections and porosity transform. Introduction The lack of porosity Information in old fields drilled prior to the availability of reliable porosity logs has frequently been a problem for log analysts. Due to the numerous operating company mergers of the recent past, many fields have changed hands, and the detailed reservoir characterization and reserves estimates needed to Incorporate these fields with existing production are, In many cases, sketchy or non-existent. Aggressive cased-hole logging and Infill drilling programs are often under taken to furnish the programs are often under taken to furnish the needed reservoir data. In some cases this can be effective, but In areas where operating economics are borderline or tubing Is In place In existing wells, these types of reservoir characterization programs are impractical. What is needed then Is programs are impractical. What is needed then Is a reliable through-tubing porosity log, preferably one that can be used for stand-one basic formation evaluation. Pulsed neutron logs fit these criteria quite well as long as care Is exercised to ensure the calculation of accurate formation parameters. Borehole effects on sigma logs have been well documented; however, environmental effects on the count rate ratio curve, and thus the porosity calculation, are lust now being addressed In a truly quantitative manner. P. 277

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production Operations Symposium, April 7–9, 1991

Paper Number: SPE-21707-MS

... ABSTRACT:

**Determination**of accurate formation temperature is needed for drilling fluid and cement slurry design,**determination**of geothermal gradients and geothermal reservoir evaluation. Most all known methods to**determine**the formation temperature are based on shut-in temperature recordings...
Abstract

ABSTRACT: Determination of accurate formation temperature is needed for drilling fluid and cement slurry design, determination of geothermal gradients and geothermal reservoir evaluation. Most all known methods to determine the formation temperature are based on shut-in temperature recordings. All these methods require long shut-in periods and result in estimates that are lower than the true reservoir temperature. A new method has been developed that utilizes temperature recordings from short time flow tests to accurately determine formation temperatures, The temperature distribution prior to production was obtained by solving the diffusivity equation for conductive heat transfer during the circulation period. This provided the initial condition for solving the continuity period. This provided the initial condition for solving the continuity equation for convective heat transfer during production by the method of characteristics. The application of the above solution is shown with a field example. Introduction Accurate knowledge of undisturbed formation temperature essential for numerous applications in drilling, completions and production. Applications include 1) drilling fluid and cement slurry design, 2) log interpretation, 3) corrosion in tubing and casings, 4) thermal stress assessment, S) hydrocarbon reserve estimation, and 6) geothermal energy extraction. Accurate assessment of downhole temperatures is required hostile environments, where abnormally high temperatures are encountered in deep and geothermal wells. The departure from the undisturbed temperature depends upon several factors: original temperature distribution; physic properties of the rock and the fluids; rates of drilling and mud circulation; and casing and cementation of the well. No analytical solution is currently available to estimate the net effect of these factors. Temperatures recorded in the wellbore can be much lower than the actual formation temperatures (differences of 40 deg. to 60 deg. F are not uncommon). Almost all known methods for determining formation temperatures rely on shut-in temperature recordings. To obtain reliable estimates of static formation temperature most of these methods require a long shut-in period and give estimates that are lower than actual formation period and give estimates that are lower than actual formation temperatures. It is desirable to have accurate estimates in relatively short times, particularly when operating in hostile environments. The goal of this study is to develop analytical solution describing the temperature distribution during circulation and production and to develop methodology to utilize temperature data from short time flow tests for estimating static formation temperatures. P. 701

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production Operations Symposium, March 13–14, 1989

Paper Number: SPE-18878-MS

... Abstract

**Determination**of reservoir characteristics from formation pressure created by underbalanced perforating may enable an operator to decide whether a well is commercially productive prior to permanent completion. With the use of several existing techniques, it is possible to analyze such...
Abstract

Abstract Determination of reservoir characteristics from formation pressure created by underbalanced perforating may enable an operator to decide whether a well is commercially productive prior to permanent completion. With the use of several existing techniques, it is possible to analyze such data. With closed chamber testing techniques, wellhead pressures are used to calculate variable sandface rates during and shortly after the well is underbalance perforated. Superposition is employed to create a rate-time function for plotting with bottom hole pressure data. The straight-line portion of the pressure versus rate-time function plot can be fitted using linear regression to solve the radial flow equation. Calculated parameters include effective permeability, skin effects and initial reservoir pressure. Also presented, is a method proposed by Soliman to analyze short producing time data. Delta pressure versus total time data is plotted on a Log-Log graph where the time axis combines producing time with build up time, A negative one (-1) slope on this plot indicates the existence of radial flow, from which reservoir characteristics can be calculated if the flow regime is known. A Gartesian plot can be used to estimate initial reservoir pressure. This paper illustrates the use of the aforementioned techniques on data collected from a multi-well project in the Gulf of Mexico. Analyses of oil wells were investigated. The results of these analysis methods for oil cases are compared with buildups performed after the wells were completed. These analysis techniques have also been applied to formation back surge data with similar results. Introduction Evaluation of backsurge pressure response has been conducted from a qualitative standpoint for many years; pressure sensitivity of mechanical gauges prevented the quantitative evaluation of this data. The advent of sensitive electronic memory recorders' with sampling rates less than five seconds and sensitivities greater than 0.1 psi has enabled the analysis of short pressure buildup transients associated with back surge and tubing conveyed perforating in high permeability wells.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production Operations Symposium, March 8–10, 1987

Paper Number: SPE-16228-MS

... drillstem testing valve automatic pressure buildup data acquisition bottomhole pressure casinghead pressure operator acoustic velocity transducer

**determination**buildup test variation drillstem/well testing liquid level interpretation microcomputer-based acoustic liquid level...
Abstract

SPE Members Abstract Production is lost when skin damage restricts fluid flow into the wellbore. The presence and degree of skin damage is most commonly determined through analysis of pressure buildup tests. This forms the basis for selecting wells as candidates for stimulation, workovers and recompletion. Traditionally these tests have been conducted using downhole pressure bombs or in the case of most pumping wells through the use of acoustic annular fluid level data which was processed off-site. The logistical complexities and high cost of these methods have limited the extent and frequency of well testing. Given the present need for production optimization and operating cost reduction, the development of a cost effective method for buildup testing represents a major advance in petroleum technology. This paper describes the design, implementation and application of a microcomputer-based system for automatically performing pressure buildup tests in pumping wells, from surface measurements, and analyzing the data in real time at the wellsite. The system is based on a portable PC which controls the operation. A solenoid-actuated acoustic source, powered with compressed gas, generates accurately repeatable acoustic pulses at variable programmable intervals. Acoustic echo travel time is interpreted in terms of position of the liquid level in the wellbore. Simultaneously the computer acquires wellhead pressure and temperature data, using high precision transducers, from which bottomhole pressure is calculated. Strip chart recordings of the acoustic signals are also made to periodically control the quality of the data. At any time during the test the operator can obtain standard graphical display of the buildup test (Horner plot, dP vs. dT, MDH, etc.) as well as conventional interpretation in terms of skin, afterflow rates and duration. Results from three field tests of the system are presented. They indicate that the system was used successfully in fairly harsh environmental conditions and was able to acquire buildup data of quality comparable to that obtainable with bottomhole pressure bombs. Interpretation of the results are in agreement to those obtained independently by DST. Introduction The present economic climate in the oil industry requires that maximum production efficiency be achieved with minimum engineering and technical manpower. Considering that the majority of US land oil wells are produced through artificial lift and the majority of these by means of beam pumping systems, it becomes apparent that there exists an increasing need to easily monitor and analyze the performance of beam pumped wells. Flowing bottom hole pressure surveys, pressure buildup tests, pressure drawdown tests, and inflow performance analyses are the principal tools available to determine reservoir pressure, formation permeability, productivity index, pump efficiency, skin factor, as well as other indicators that can be used in the optimization of producing well operations. These techniques are widely used in flowing wells and in some gas lift wells, where the pressure information is easily obtained from wireline conveyed bottomhole pressure recorders. The presence of the sucker rods in beam pumped wells essentially precludes practical, routine, direct measurement of bottomhole pressure, thus eliminating the single most important parameter for well analysis. Permanent installation of surface indicating bottomhole pressure gages have not become cost effective, nor have wireline measurements through the annular space. P. 427^

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production Operations Symposium, March 8–10, 1987

Paper Number: SPE-16225-MS

... to

**determine**reservoir properties. The classical liquid filled reservoir analysis has been extended to gas wells by three different approaches. The first is by analogy to the classical liquid filled reservoir analysis. This is possible through the use of average gas viscosity (jig), gas z factor (z...
Abstract

SPE Member Abstract A theoretical basis for pressure transient analysis of gas wells with emphasis on the real gas pseudo pressure approach is outlined. An analysis procedure is developed to analyze wells either injection or producing predominantly C02 or enriched gas. This procedure 's used to calculate flow capacities and skin factors from pressure transient tests in injection and production wells from two C02 projects. A computer program is documented which aids in the analysis of gas wells with the real gas pseudo pressure. Finally, example calculations are shown for a C02 well, an enriched gas well, and an enriched gas well contaminated with C02 / H2S. Introduction Pressure transient analysis is one of the most widely used methods in reservoir engineering to obtain in-situ reservoir data. A variety of transient testing techniques have been developed including pressure buildup, pressure drawdown, injectivity, pressure falloff, and interference testing. Reservoir data calculated from these techniques includes wellbore volume, wellbore damage or stimulation, reservoir pressure, flow capacity (permeability), reserves, fracturing, reservoir discontinuities, fluid discontinuities and swept volume. Pressure transient analysis was developed for liquid filled reservoirs with a small total compressibility. The solution of the diffusivity equation for a liquid filled reservoir results in a derivative of pressure with respect to time. This is the basis of the pressure vs time plot used to determine reservoir properties. The classical liquid filled reservoir analysis has been extended to gas wells by three different approaches. The first is by analogy to the classical liquid filled reservoir analysis. This is possible through the use of average gas viscosity (jig), gas z factor (z), and gas compressibility (Cg) at the reservoir temperature, T, and average reservoir pressure, p. These assumptions are good in most was reservoirs below 2000 PSI as long as pressure gradients in the reservoir are small, since for most natural gas wells, ug z at these conditions is approximately constant, Figure 1. Above this pressure, (ug - z) / p is approximately constant. This gives rise to the second approach, where p2 instead of p is analyzed as a function of time. The p2 vs time relationship is used because the solution of the diffusivity equation for a gas filled reservoir yields a derivative of p2 with respect to time. In many cases the assumptions of constant ug, z, Cg, and small pressure gradients are not met and both the p and p2 methods are invalid. As a result, a third approach was formulated which accounts for variations in jig and z as a function of p and allows large pressure gadients making the approach much more accurate. This is achieved through the use of a real gas pseudo-pressure function, m(p), which is a function of p, ug, and z and which matches Figure 1 exactly. With this function, the solution of the diffusivity equation for a gas filled reservoir results in a derivative of m(p) with respect to time; therefore m(p) instead of p or p2 is analyzed as a function of time. The m(p) function has been applied extensively in natural gas reservoirs and many sources of natural gas m(p) data are available. The use of the real gas pseudo-pressure is not limited to gas wells, but can be applied to any flowing fluids as long as effective viscosities and compressibilities can be calculated. The wide application of miscible gas processes in the field has given rise to another set of pressure transient tests which can be analyzed with the real gas pseudo-pressure; those injecting or producing predominantly miscible gas, either C02 or enriched natural gas. This report documents application of the m(p) approach to such wells. THEORETICAL BASIS Pressure transient analysis is based on the radial diffusivity equation. This equation may be solved for slightly compressible liquids (the classical pressure transient analysis) yielding the derivative of p with respect to time, for an ideal gas yielding the derivative of p2 with respect to time, and with the real gas pseudo-pressure yielding the derivative of m(p) with respect to time. P. 517^

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production Operations Symposium, March 10–12, 1985

Paper Number: SPE-13810-MS

... to 15,000 psi in corrosive (CO2 and H2S) environments. pressures up to 15,000 psi in corrosive (CO2 and H2S) environments. Equations and charts are presented herein for

**determining**static bottomhole pressures from acoustic and well data. Also, a special technique is pressures from acoustic and well...
Abstract

Abstract Acoustic instruments have been used routinely for many years as an aid in analyzing well performance of normal-pressure oil producers. Recent developments in equipment and techniques now permit more accurate calculations of acoustic static bottomhole pressures at surface pressures up to 15,000 psi in corrosive (CO2 and H2S) environments. pressures up to 15,000 psi in corrosive (CO2 and H2S) environments. Equations and charts are presented herein for determining static bottomhole pressures from acoustic and well data. Also, a special technique is pressures from acoustic and well data. Also, a special technique is recommended for shutting-in a well which in most cases will yield more-accurate results. This method has been programmed for an inexpensive, portable notebook-size computer which can be used in the field to easily perform these calculations. Introduction The liquid level in a well may be determined acoustically by generating a pressure pulse at the surface and recording the echos from collars, obstructions, and liquid level. A blank cartridge was the conventional source of pressure pulse until development of the modern gas gun. On wells having less than 100 psi, the gas gun volume chamber is pressurized to approximately 100 psi in excess of well pressure. The gas is then rapidly released into the well to create the pressure pulse. On wells having pressures in excess of 100 psi, the volume pressure pulse. On wells having pressures in excess of 100 psi, the volume chamber in the gas gun is bled to a pressure less than the well pressure. Then, a valve is rapidly opened to permit wellhead pressure to expand into the volume chamber and create a rarefraction pressure wave. A microphone converts the pressure pulses reflected by collars, liquid, and other obstructions (or changes in area) into electrical signals which are amplified, filtered, and recorded on a strip chart (Fig. 1). The liquid level depth can be determined by counting the number of tubing collars to the liquid-level reflection. Changes in cross-sectional area are also recorded. When these changes are known, they can be used as depth references to determine liquid-level depth. Also, the distance to the liquid level can be calculated by travel time from the acoustic chart and acoustic-velocity data. Acoustic measurements were generally obtained by "shooting" down the casing/tubing annulus in packerless completions (Fig. 1). p. 165

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Production Operations Symposium, February 25–27, 1979

Paper Number: SPE-7802-MS

... correction factor spe 7802 practical concern accurate measurement liquid vapor gravity correction calculation calorimeter water vapor

**determination**MCF SPE 7802 PRACTICAL CONCERNS IN METERING FLUIDS FROM PRODUCTION OPERATIONS by W. J. Templeton, Cities Service Co. SPE Society of Petrolelin...
Abstract

Abstract Accurate measurement of oil and gas is of vital concern. Measurement of these vapor and liquid streams by mass, volumetric, and energy techniques are reviewed to better provide an understanding of the type of measurement recommended for use in each case. Improved accuracy in primary measuring devices, auxiliary equipment, and sampling are reviewed from a practical aspect, whereby measurement accuracy and ultimately dollars can be realized. The accuracy obtained in measurement directly affects the cash register and the bottom line of your financial sheet. The practical concerns presented in the metering of fluids will improve the accuracy of your oil and gas measurement. Introduction As producers, there are two principal products that we are interested in measuring, namely, oil and gas. Along with the principal products that are measured are contaminants that we do not want to buy-such as water, BS, carbon dioxide, hydrogen sulfide, nitrogen, oxygen, and water vapor. It is necessary to measure the contaminants so that we do not buy them, but deduct the contaminant volume from the total measurement. Subjects covered in this presentation will be the types of measurement determinations used in production operations, such as (1) volumetric, (2) mass, and (3) energy. With each type of measurement, the practical aspects of the primary measuring devices practical aspects of the primary measuring devices such as orifice, positive displacement, turbine, static, pressure and temperature recorders, and auxiliary equipment such as samplers, calorimeters, densitometers, and contaminant measurement will be reviewed. PRACTICAL CONCERNS IN METERING PRACTICAL CONCERNS IN METERING What are the three types of measurement and when and how are they used? Volumetric Measurement Volumetric measurement is the method of determining a volume of either a liquid or gas and giving the units of measurement in define quantities at standard conditions such as cubic feet, gallons, or barrels, or corresponding metric units. Volumetric measurement is used when the physical properties of the fluid being measured are known and, properties of the fluid being measured are known and, therefore, the volumes being measured can be corrected to standard conditions. Physical properties referred to are the coefficient of expansion properties referred to are the coefficient of expansion and compressibility of liquids and super compressibility of gases. Volumetric measurement is performed by general industry meters, such as orifice, positive displacement, and turbine meters. The equations for determining volumes are as follows. Gas Measurement by Orifice Q = . . . . . . . . . . . . . . . . . . . . . . (1) where Q = quantity rate of flow at base conditions, cu ft/hour Fb = basic orifice factorhw = differential pressure across the orifice, inches water Pf = absolute static pressure, psia Other factors are explained in Ref. 1. Turbine or PD Meters for Gas Measurement Q = (Dial Diff) (C) (C) (MF),............(2)t p where Q = quantity of flow at base conditions Dial Diff = difference between ending and beginning meter dial readings Ct = correction for temperature to correct volume readings to standard conditions C = 460 + 60 Ft 460 + (Flowing Temp degrees F)

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Oklahoma City Regional Meeting, February 21–22, 1977

Paper Number: SPE-6465-MS

...-values from the Density-Acoustic combination, provides a basis for

**determining**cutoff permeability. Computed water saturations compare well with the conventional Swq-equation. The new method is applicable to minimum logging combinations as frequently run in development wells. Introduction Log...
Abstract

Abstract A simplified shaly sand analysis that uses a resistivity-one porosity log combination is discussed. The method involves estimation of shaliness by conventional techniques and, if necessary, porosity corrections for gas effects. A "pseudo-q" factor, which compares favorably with q-values from the Density-Acoustic combination, provides a basis for determining cutoff permeability. Computed water saturations compare well with the conventional Swq-equation. The new method is applicable to minimum logging combinations as frequently run in development wells. Introduction Log analysis of shaly pay sands has received considerable attention. In many investigations, the clays and fluids occupying the interstices of the sand matrix are treated as a slurry, and the effect of both clay and hydrocarbons is taken into account. Based upon the dispersed clay model, the formation water saturation (Swq) has been estimated successfully in the U.S. Gulf Coast area for many years. Resistivity of the disseminated clay (Rc)is not exactly constant. However, an average value should be useable for a given geological area, since under most circumstances even relatively large changes in the value of Rc cause only small variations in the computed water saturation. Generally, the resistivity of clays dispersed in the pore space of a reservoir rock is less than that of adjacent shales. Values of Rc = 0.5 Rsh for the shallow Wilcox of Louisiana and Mississippi have been given. For the Gulf Coast we recommend the use of Rc = 0.4 Rsh, which closely agrees with the concept of multiple Rw-values proposed previously. previously. BASIC CONSIDERATIONS Considering the response of porosity tools, such as the Density and Acoustic, to the shaliness of a formation, it is possible to compute water saturation, with one porosity tool only. In addition, it is then possible to derive a pseudo-q value, which gives an indication for the amount of clay in the formation and, therefore, estimates the likelihood for reservoir producibility. Response of Density and Acoustic logs in shaly, water bearing sands can be expressed such as: ..........Density........(1)

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Oklahoma City Regional Meeting, March 24–25, 1975

Paper Number: SPE-5404-MS

.... These, in conjunction with the original open-hole logs (usually a vintage Electrical Survey or a Gamma Ray-Neutron log) permit much better accuracy and reliability in the

**determination**of porosity, fluid saturation and in some cases the type of hydrocarbon behind the pipe. This paper presents several...
Abstract

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the Oklahoma City SPE Regional Meeting, to be held in Oklahoma City, Okla., March 24–25, 1975. 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 presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is 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. 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 When production from a well falls below the profitable level, usually due to declining profitable level, usually due to declining reservoir pressure, the producer must decide whether to abandon, recomplete, or begin secondary-recovery operations. Until recently, the choice was made very difficult by the scarcity of reservoir-rock information obtainable from the existing logs. The development of new took and techniques for logging in cased holes has greatly improved this situation. A modern logging program for these old wells might consist of a Dual-Spacing Neutron Decay Time tog, a Compensated Neutron log, and, where applicable, a cased hole Formation Density log. These, in conjunction with the original open-hole logs (usually a vintage Electrical Survey or a Gamma Ray-Neutron log) permit much better accuracy and reliability in the determination of porosity, fluid saturation and in some cases the type of hydrocarbon behind the pipe. This paper presents several examples of Mid-Continent wells which were logged by such modern techniques. In each, the cased-hole logs allowed the producer to select with confidence the most appropriate action for his well. Introduction Developments in technique and equipment have brought a new order of reliability to log evaluation in cased holes. The key to these advances is the Dual-Spacing Thermal Decay Time device (TDT*-K). Also useful are the Compensated Neutron and Formation Density logs, which can be run in combination, and which under favorable conditions will provide good porosity determination and gas detection in cased holes.