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Results
Summary A comprehensive coupled wellbore/reservoir simulator was developed to study the behavior of single-phase oil flow in the wellbore. The wellbore is modeled numerically where mass, momentum, and energy of the fluid are conserved, while the reservoir fluid flow is treated analytically. Energy transport occurs through tubulars, cement sheaths, and the formation by conduction. However, both conductive and convective heat-transport mechanisms are operative for the annular fluid. Heat losses through seawater and air are also modeled for a well producing in an offshore environment. A sensitivity study shows that heat loss through seawater becomes significant for long submerged tubulars (>2,000 ft), but is marginal for shorter pipes because of the fluid's short residence time. Further, a deviated well loses more heat to formation than its vertical counterpart for the same reason. Of the major variables, thermal conductivity of the annular fluid plays a key role in heat retention and, therefore, the wellhead temperature (WHT). We have identified the phenomenon of thermal storage. This storage behavior is associated with heat absorption or desorption by cement sheaths and tubulars and is reflected as the time taken to attain equilibrium WHT for a given flow rate. A longer storage period occurs at low flow rates because of lower associated fluid enthalpy. Field data were used to demonstrate various applications of the simulator. We showed that both drawdown and buildup data of bottomhole pressure (BHP), wellhead pressure (WHP), and WHT can be modeled successfully given the tubular, completion, and reservoir data. Conversely, given the wellhead measurements (WHP and WHT), BHP values comparable to those measured can be computed. Introduction Single-phase production to surface is possible for an oil having low-saturation pressure and/or when produced against high wellhead backpressure. Conventional well-test design or interpretation for single-phase production involves use of either a constant or a changing storage model that describes wellbore fluid flow. These simplified analytic models are not designed to fully capture physical phenomena associated with fluid momentum and energy transports. Consequently, wellbore dynamics influencing the early-time data often are not understood properly. Perhaps more important, one cannot use these analytic models to predict a reliable test response in many situations. These situations include flow occurring from high-temperature reservoirs and/or when the fluid undergoes significant cooling in deepwater offshore wells. While great strides have been made in developing analytic models for flow in the reservoir of increasing complexity, the work toward understanding transient wellbore fluid flow has just begun. For instance, recent models shed some light on the physical behavior of wellbore phase redistribution during a buildup test. These studies consider isothermal wellbore only, although one uses a more realistic fluid temperature profile at the onset of shut-in. Models have been developed to understand the general transient fluid flow behavior during both flow and shut-in conditions in a coupled system: those involving an isothermal wellbore and those involving nonisothermal systems. In all cases, a complete numeric formulation was obtained for the coupled system. More recently, we reported a hybrid modeling approach for simulating single-phase gas flow. In this efficient formulation, the flow in the wellbore is modeled numerically while that in the reservoir is modeled analytically. We extend the same approach in this work to model single-phase oil flow. Aspects of Simulator Development Formulation of this model is analogous to the single-phase gas model described earlier.Fig. 1 presents a schematic of the system that was modeled in this work. For brevity, we present the constitutive equations and their finite-difference analog in the Appendix. Here, we discuss two aspects of modeling that are important when conversion of WHP and WHT to BHP is sought in reverse simulations. BHP calculations from WHP and WHT data require fluid-temperature profile in the wellbore for proper fluid-properties estimation. In our earlier gas-well simulation, we used a linear temperature profile to initiate computation. This procedure can be improved significantly by recognizing that an analytic solution exists for computing the fluid-temperature profile, as given byEquation 1 Note that Eq. 1 was obtained, with some simplifications, for steady-state flow condition. However, the same equation can be extended to unsteady flow situations by evaluating the relaxation distance LR at each timestep from the measured WHT and the known BHT. Our simulations with synthetic and field data support this contention. A vexing problem often arises when one attempts to compare the computed WHT with those measured in the field. The problem originates from the WHT measurement. If one merely straps a thermometer around a section of the wellhead instead of inserting a thermocouple into the tubing fluid, the required core fluid temperature is not measured. Estimates of temperature from an indirect thermometry may be obtained in the following manner:Equation 2 In Eq. 2, the heat-transfer coefficient hTh is lower than the overall coefficient, U, for the wellbore given by Eq. A-14, because of the additional resistance between the wellbore and the thermometer. The goodness of contact between the thermometer and the wellhead metal in addition to the material used for strapping the thermometer presents a challenge for estimating hTh. In our simulations, we used a value of hTh that best fits the available data. Thus, when temperature data are collected under less than satisfactory conditions, this procedure requires us to consider one additional parameter. As shown, the field example gives credence to the proposed procedure. Sensitivity Study We explore the sensitivity of certain key parameters on the transient behavior of pressure and temperature both at wellhead and bottomhole. The Supplement presents the wellbore/reservoir data used to generate the synthetic cases.
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Summary Temperature logs have been commonly used to evaluate fracture height by locating cool anomalies which indicate the locations where cool fracture fluids were injected. However, instead of cool anomalies, warm anomalies (called "warm noses") often occur on temperature logs run after fracture treatments. When interpreting fracture height from a temperature log, warm anomalies make it difficult to identify the top and bottom of the fracture. We believe that a plausible reason for warm anomalies is that the wellbore and the fracture are not coincident over the entire extent of the fracture; instead, away from the perforations, the fracture and the wellbore may be separated a finite distance that varies with depth. This paper investigates the effect of the existence and magnitude of the displacement between the wellbore and the fracture on well bore temperature behavior after fracturing. The results obtained explain the "warm noses" on shut-in temperature logs run after a fracture treatment and, more generally, provide an improved method for interpreting fracture height from temperature logs. A mathematical model has been developed to simulate the wellbore temperature after fracturing for cases where the wellbore and the fracture are not coincident for the entire extent of the fracture. The study shows that the temperature behavior strongly depends on the pattern and the magnitude of the displacement. When the fracture is perfectly connected with the well bore, the cool region on the log indicates the top and bottom of the fracture clearly. However, the cool region is much smaller than the fracture height if the wellbore deviates from the fracture at a constant angle away from the perforations - a situation that may occur in a well that is deviated slightly from vertical, for example. Furthermore, "warm noses" appear on the log if the well spirals in a helical trajectory because the spacing between the wellbore and the fracture will vary with depth for this geometry. Therefore, when evaluating a post-fracture temperature log, the possibility of a deviated wellbore-fracture system must be considered to avoid misinterpreting the fracture height. Longer shut-in times are shown to improve the fracture height interpretation. Introduction Currently, the most widely used method for determining the height of a hydraulic fracture is to run a temperature log on the shut-in well shortly after the fracturing treatment.
- Well Completion > Hydraulic Fracturing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Summary Gas wells frequently exhibit changing storage during a transient test because of high fluid compressibility. Further complications may arise due to beat exchange between the wellbore fluid and the formation, especially in high-temperature reservoirs. Thus, fluid temperature changes during a transient test, thereby complicating test interpretation when surface measurements must be used in a hostile downhole environment. In this work we present a transient wellbore/reservoir model for testing gas wells that is particularly useful for high- temperature reservoirs. The model can be used in a forward mode, given reservoir and wellbore parameters, to predict pressure and temperature at any depth during a transient test. The wellbore model formulation involves the use of mass, momentum, and energy balances for a single-phase gas together with the PVT relation to generate the constitutive equations. The reservoir fluid flow is modeled using the standard analytic approach, including superposition effects. Heat transport in the wellbore accounts for conductive and convective heat flow through the annul us fluid and conductive heat transport through the tubulars and cement sheaths into the formation. The finite-wellbore radius solution of the thermal diffusivity equation accounts for heat flow in the formation. Energy balance for the fluid accounts for the Joule-Thompson expansion. A sensitivity study provided some insights into the effect of process variables on wellbore pressure and temperature. As expected, fluid flow rate is shown to have a very significant impact on the wellhead pressure and temperature. Clearly, the temperature rating of surface equipment could limit the maximum production from some wells. Heat transport in the annulus between the tubing and casing also strongly influences wellhead fluid temperature. For example, a fluid with a low-heat transfer coefficient, such as a or oil-based mud, would allow the wellbore gas to retain much of the enthalpy, leading to high fluid temperatures at the wellhead. Unlike previous formulations, this model accounts for the energy absorbed (or released) by the tubulars and the cement sheaths, which is a significant fraction of the energy exchange between the wellbore and the formation at early times. A consequence of accounting for heat capacity of the wellbore system is that rapid temperature rise or fall during a test is dampened, mimicking the actual field response. Introduction A routine well-test interpretation or forward modeling invokes the well-known constant-storage model. When a test is associated with either increasing or decreasing storage, one could use the Fair or the Hegeman et al. model. These wellbore models are popular because they are operable in Laplace space and, therefore, can be linked easily with most analytic reservoir models whose solutions are also available in Laplace space.
- Europe (0.70)
- North America > United States > Texas (0.47)
- Africa > Tanzania > Indian Ocean > K Formation (0.99)
- North America > United States > Louisiana > Mississippi Field (0.98)
- North America > United States > Gulf of Mexico > Norphlet Formation (0.98)
- North America > United States > Texas > East Texas Salt Basin > East Texas Field > Woodbine Formation (0.97)
Summary A family of production decline curves for low-pressure gas reservoirs are presented for radial flow geometry with closed outer boundary and with a centrally located well. The proposed production decline curves are applicable to conventional gas reservoirs that produce gas and water simultaneously. The proposed decline curves exhibit unique characteristics for a variety of reservoir and fluid properties and pressure specifications at the well. The performance of the proposed decline curves were investigated against two different numerical simulators, and they were found to be capable of predicting the production of conventional gas reservoirs under two-phase flow conditions with good accuracy. The decline curves presented in this paper have the potential of providing a practical tool by which production performance of gas reservoirs under two-phase flow conditions can be predicted for pragmatic purposes without using sophisticated numerical models. Introduction To formulate long-term economic predictions related to gas reservoirs, it is necessary to predict the long-term withdrawal rates physically possible for each well. Rate/time decline curve extrapolation is one of the more often used tools of petroleum engineering. For a long period of time, various decline methods were regarded as empirical and not scientific. A new direction of decline curve analysis was introduced by Slider. He developed an overlay method to analyze rate/time data. This method is similar to the log-log type-curve matching procedure used to analyze pressure-buildup and -drawdown data. This paper provides a type-curve approach to analyze production decline characteristics of gas reservoirs that produce water and gas simultaneously. A large number of gas reservoirs are wet sands, and coproduction of gas and water takes place. Such reservoirs can be found in the Midwest and North Eastern U.S. (two-phase flow in these reservoirs is more significant during the early stages of the production), and in gas fields of the Middle East. Some gas fields in Europe have also reported water production. There are situations where initial water saturation is less than the critical water saturation of the formation, and the water does not flow. To take the presence of water phase into consideration, one needs to decrease formation porosity by subtracting the portion of the PV occupied by the immobile water phase. In most of the wet sands, however, initial water saturation exceeds the formation critical water saturation, and water becomes a dynamic phase and is produced simultaneously with gas. Under these conditions, treatment of a two-phase gas reservoir similar to a single-phase gas reservoir will generate erroneous results. In a two-phase gas reservoir, relative permeability characteristics of the formation control the flow of fluids through the formation. Therefore, a dry sand reservoir and a wet sand reservoir with similar properties exhibit different production and depletion characteristics. Petroleum engineering literature contains production decline curves generated for single-phase gas reservoirs. These decline curves can be used in studying the production performance of gas reservoirs that are experiencing single-phase flow conditions. The use of these production decline curves to predict the performance of gas reservoirs undergoing two-phase flow conditions will lead to overestimation of the capabilities of the field in hand. The purpose of this study is to provide a practical tool by which performance prediction and reservoir characterization of the wet gas sands can be achieved with good accuracy.
Summary The existence of specific flow regimes during horizontal well transient tests has been the subject of meaningful interpretation developments in the recent literature. This paper presents a field example from the Bombay High field, paper presents a field example from the Bombay High field, offshore India, where simultaneous measurement of downhole pressure and flow rate enables the identification of the early and late-time pseudo-radial flow regimes, and, to a lesser extent, of the intermediate linear flow. Analysis of these successive flow regimes yields estimates of the anisotropic formation permeabilities and the mechanical skin factor. The second step of the interpretation methodology developed here consists in refining these estimates through a weighted non-linear least square history-match of the measured transient data. Matching the transient flow rate is more appropriate, under certain circumstances, than the pressure response; for this purpose, analgorithm has been developed to compute well purpose, an algorithm has been developed to compute well rate from transient pressure, given the characteristic response model of a horizontal well. The refined parameters obtained for the field example are compared to the results of an extended conventional test of the same horizontal well. Good agreement in terms of horizontal permeability enhances the confidence level of the other parameters, namely the vertical permeability and true mechanical skin. Introduction The interpretation of transient tests conducted in horizontal wells has received considerable attention in the past few years. The literature on this subject spans the past few years. The literature on this subject spans the whole spectrum from response modeling and flow regime identification to field application. An extensive bibliography can be found in Ref. 1, whereas Ref. 4cites some more recent developments. In the present study, a general two step methodology for transient test interpretation is applied to horizontal wells. The methodology is explained in detail in the theory section. it is illustrated through the analysis of field data from a horizontal well test conducted by ONGC in the Bombay High oilfield, offshore India. The field example section gives a detailed account of the interpretation procedure and provides ample discussion of the relevant issues. provides ample discussion of the relevant issues. The only published analysis of an actual horizontal well test known to the authors did not include measured downhole transient flow rates. This may therefore be the first field example of a horizontal well test where measured downhole flow rate and pressure are successfully interpreted and history-matched. The analysis presented here brings out the importance of measuring downhole transient flow rates during horizontal well tests in order to ensure unique and accurate determination of the anisotropic permeabilities and the true skin factor. Algorithms developed to enable the history-match of flow rate using measured wellbore pressure as input to an analytical simulation model are presented in Appendix A. THEORY AND INTERPRETATION TECHNIQUE GENERAL METHODOLOGY The methodology for the interpretation of transient tests during which downhole pressure and flow rate are simultaneously measured has evolved over the years. It has recently been reviewed in Ref. 5 and consists of two steps. Step 1: Diagnostic Plots and Direct Analysis The pressure response and its derivative are analysed in order to diagnose the characteristic behaviour of the system and identify the time periods of a transient during which specific flow regimes are dominant.
- Asia > India > Maharashtra > Arabian Sea > Bombay Offshore Basin > Mumbai High Field > L-V Formation (0.99)
- Asia > India > Maharashtra > Arabian Sea > Bombay Offshore Basin > Mumbai High Field > L-IV Formation (0.99)
- Asia > India > Maharashtra > Arabian Sea > Bombay Offshore Basin > Mumbai High Field > L-III Formation (0.99)
- (2 more...)
Abstract With the recent Surge in horizontal welldrilling, increased attention has been placed on assessing horizontal well productivity and the optimization of completion design. Transient pressure analysis has long been the standard for vertical well productivity measurement and evaluation. The complex geometry associated with horizontal wells makes transient pressure analysis quite difficult and also challenging. Recent technical developments have shown that combining drawdown and buildup tests, with downhole transient flow rate measurements can significantly enhance the quality of interpretation. However, uncertainty in the production interval and the associated production profile within the horizontal section can make the interpretation of these tests challenging and at times can result in nonunique answers. This may cause the interpreter to estimate a low well productivity and thus elevate the chances of premature well abandonment. The paper first discusses horizontal well transient pressure analysis methodology and then illustrates the development of a technique that can incorporate the production interval and production profile data. The proposed technique can be applied to specialized plots as well as to type curve and history matching methods. The technique can also optimize welltest design by forward modeling. Using the technique to optimize test design and to enhance the interpretation answers is illustrated via an actual field example. Introduction The number of horizontal wells projected to be drilled this year is more than double that was drilled last year and about eight times that of the year before last. This surge in horizontal well drilling for increased well productivity has brought attention to assessing the wellproductivity and completion design optimization of these wells. The pressure transient test has long been the standard in characterizing the vertical well formation-reservoir system(wellbore geometry, outer reservoir boundaries, faults, fractures, partial penetration, drive mechanism, etc.) and estimation of its flow parameters (permeability, reservoir pressure and skin factor). The complex geometry associated with horizontal wells can make pressure transient analysis difficult and challenging. Such a test, however, rewards us with additional reservoir flow parameters that are needed to adequately characterize the formation, but requires more parameters to adequately quantify well performance. The first two response models of pressure transient behavior of horizontal wells were presented concurrently by Goode and Thambynayagam and Daviau et al. In addition to the identification of the two radial flow regimes by Daviau et al., Goode and Thambynayagam identified an intermediate time linear flow regime. Since then the literature on this subject has considerably expanded to include more response modeling, test interpretation methodology by Kuchuk et al. and Joseph et al., and field applications by Kuchuk et al. and Shah et al. P. 355^
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Summary Interpretation models for layered reservoirs cannot be used effectively until a model has been identified for each reservoir layer. This paper introduces a new deconvolution form for presentation of multilayer transient(MLT) test measurements that is analogous to the log-log diagnostic plot used for model diagnosis of conventional transient test data. Introduction The MLT test technique was introduced by Kuchuk et al. in 1986. Since then, more than 100 MLT tests have been conducted in water injection, oil, gas, and gas injection wells. Permeabilities ranging from a few millidarcies to several darcies have been determined layer by layer along with skin factor estimates and the average pressure in each layer. Several MLT case studies have been published. Kuchuk et al. 2 analyzed a two-layer water injector. published. Kuchuk et al. 2 analyzed a two-layer water injector. Morris interpreted a two-layer oil reservoir with one infinite-acting layer and one layer with pressure support from an aquifer. Ref. 4 described a four-layer oil well example and Joseph et al. 5 provided an interpretation for a four-layer oilwell with parallel fault boundaries. parallel fault boundaries. Figs. 1 through3 show test configurations for commingled layers. The conventional way to test each layer is with isolation packers (Fig. 1). The isolated zone test string is lowered with the packers (Fig. 1). The isolated zone test string is lowered with the drillstem or tubing and thus is costly to conduct. Data interpretation is straightforward. The MLT test (Fig. 2) is conducted with a production logging too] that continuously measures pressure and sandface flow rate. Ref. 6describes the procedure pressure and sandface flow rate. Ref. 6 describes the procedure for MLT tests, which are conducted in cased wells. MLT test data interpretation is complicated by the presence of near-wellbore features, heterogeneity, or outer boundaries that cannot be identified readily layer by layer with current interpretation techniques. Fig. 3 shows an alternative testing technique called the commingled single-layer transient (CSLT) test that uses a production logging tool with more than one flowmeter. In an example of a CSLT test in a gas well, the analysis suggested that one or more of the layers had been vertically fractured. The CSLT test is almost as straightforward to interpret as an isolated zone test, but logistical and calibration difficulties discourage widespread application of this technique. Clark et al. provided another extension of the MLT test technique for unstable flow in oil wells produced under gas lift. produced under gas lift. With recently published analytical models, each layer in a multilayer reservoir simulation can be described by any model previously developed for single-layer interpretation. Ehlig-Economides previously developed for single-layer interpretation. Ehlig-Economides and Joseph provided a comprehensive survey of layered reservoir models published before 1985 and introduced a general layered model for commingled zones with communicating (crossflowing) layers in each zone. Mavor and Walkup described the "parallel resistance" model forcommingled layers. This generalization provides a multilayer model comprising a collection of single-layer models that have been formulated as solutions in Laplace space, Kuchuk and Wilkinson offered an elegant mathematical formulation for the commingled multilayer model using Green's functions. This paper included additional model features, such as layers with different initial pressures or layers opened to flow at different times. Larsen produced solutions for zones at different initial pressures and for zones with different fault boundaries. Bennett pressures and for zones with different fault boundaries. Bennett et al. provided a solution for layers commingled in a single vertical fracture, which was extended by Camacho-V. et al. for unequal layer fracture half-lengths. Spath et al. implemented a layered model that included fractured layers commingled in a well- bore with elliptical swept regions (for water injection wells), homogeneous or heterogeneous layers, and layers completed with a horizontal borehole. A complete characterization of the layered reservoir includes an adequate model for each layer. For isolated zone tests, selection of the interpretation model is accomplished by use of a log-log plot of the pressure change and its derivative. For CSLT tests, a log-log plot of the convolution derivative is used to diagnose the model. MLT test interpretations includes selective inflow performance (SIP) analysis, sandface rate-convolved (SFRC) analysis above each zone, sequential analysis, and simultaneous analysis. The MLT test interpretation provided by these steps determines permeability, skin factor, and average pressure for each layer. Parameters for other features, such as partial penetration. heterogeneity, and fault boundaries, can be estimated with sequential and simultaneous analyses if layer models have been diagnosed. Diagnosing the response for a given layer is complicated because the convolution derivative for each MLT measurement represents the combined response of all layers below the flowmeter. The new presentation of MLT test data in this paper resembles the conventional single-layer response as closely as possible, thus revealing the individual layer behavior. This presentation can be used with artificial intelligence to automate model selection and with nonlinear parameter estimation for automated matching. MLT Test Deconvolution The MLT test involves acquisition of transient flow rates measured continuously with a stationary flowmeter sensor situated just above an interval to be tested. At this depth. the flow rate is measured at reservoir pressure and temperature in barrels per day. Hence, in this paper, q is used to denote flow rate at reservoir conditions with (q) referring to a measurement just above Laver J. q is used for flow rates measured at the surface in stock tank barrels per day. Appendices A through D describe detailed formulations that are used for single-layer reservoirs and that can be used for multilayer systems as described in this section. When pressure and sandface rate are measured simultaneously, the Gladfelter deconvolution, or rate-normalized pressure, resembles the pressure-transient response to a step change in the sandfacerate. For the CSLT test in Fig. 3, flowmeters are positioned above and below the test interval. A simple subtraction, positioned above and below the test interval. A simple subtraction, [q (t)] - [q (t)], provides a direct measure of the zone flow rate. Once the continuous zone rate is known, a log-log plot of the convolution derivative (Appendix C) or the deconvolution derivative(Appendix D) is used to diagnose a reservoir model for the single layer. For the MLT test, measurements are made above and below the same interval, but they are acquired at different times with only one flowmeter. The MLT measurements are taken under flowing conditions and may be subject to some fluctuations in the surface flow rate. Also, each MLT is initiated by a change in the surface flow rate of arbitrary magnitude. As a result, it is not possible to subtract the flow rates from transient measurements taken at different times. However, if the time-dependent flow rate change from each transient is normalized(divided) by the simultaneously measured pressure change, the resultant pressure-normalized rate has been corrected for flow rate fluctuations and for the magnitude of the surface flow rate change that initiated the transient. The pressure-normalized rates computed from data acquired below anpressure-normalized rates computed from data acquired below an interval are subtracted from those computed from data acquired above the same interval. The reciprocal pressure-normalized rate (RPNR) difference is a convenient extension of the Gladfelter deconvolution. The log-log plot of the RPNR and its derivative with respect to the logarithm of time provides response patterns like those of the pressure change and its derivative. SPEFE P. 215
- Research Report (0.35)
- Overview (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.54)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Summary A new time-dependent method of oxygen-activation logging, now being used in the Kuparuk River field on the North Slope of Alaska, provides critical data for waterflood performance evaluation, assessment of ultimate recovery, and evaluation of potential for infill drilling and EOR projects without the use of radioactive tracer materials. Introduction The Kuparuk River field is on the North Slope of Alaska, approximately 40 miles west of the Prudhoe Bay field (Fig. 1). It is one of the largest oil fields in the U.S., producing approximately 300,000 BOPD. A waterflood begun in 1983 now covers 85% of the 115,000 acres currently developed. Evaluation of waterflood performance is essential for efficient management of the existing waterflood, assessment of ultimate production, and determination of infill drilling potential and enhanced recovery processes in the field. Decisions regarding further development require early commitment of multimillion-dollar investments. Therefore, early evaluation of Kuparuk field waterflood performance is a critical component of the valuation process. Production occurs from two horizons referred to as Sands A and C. For waterflood management purposes, selective single completions are used to isolate the prolific Sand C behind production tubing and to enable fracture stimulation of the lower Sand A. Fig. 2 shows a selective single completion for an injection and a production well. Because all current injection wells initially were completed for production service before conversion, all wells have hardened blast joints across the Sand C perforations to minimize the potential for erosional cutting of the tubing. Given this completion type, a direct measurement of vertical conformance is impossible across Sand C with conventional production-logging techniques. Attempts to obtain vertical conformance measurements with radioactive-tracer slug methods have been highly qualitative. Significant tracer mixing and dilution occurs as the tracer passes through the injection mandrels at the high velocities associated with normal injection rates exceeding 3,000 BWPD. The resulting signal is poorly defined. Surveys were complicated further by the need for large amounts of radioactive tracer to obtain a high-enough count rate to be pleasured through the blast joints. Given the highly stratified nature of Sand C and the significant differences in permeability and thickness between Sand C layers, a more quantitative measurement of vertical sweep was necessary. During the past year, oxygen-activation logging has been applied successfully to injection and production wells to identify thief zones behind the production tubing and to provide the quantitative vertical-sweep information necessary for better waterflood management. This measurement provides a new capability to trace water at high flow rates and is well-suited to measure water flow in the tubing/casing annulus. Information obtained to date has been used to plan a polymer treatment to improve vertical sweep, to verify floodable pay, and to analyze injection performance of the Kuparuk waterflood, immiscible water-alternating-gas (WAG), and smallscale EOR project. An operational benefit is that the need for radioactive tracer materials has been eliminated.
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay (0.81)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.54)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- North America > United States > Alaska > North Slope Basin > Greater Point McIntyre Area > Point McIntyre Field (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > Kuparuk Field > Kuparuk Formation (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Summary To assess the level of differential layer depletion in the Ameland gasfield, production logging surveys were conducted and interpreted with a multilayer testing (MLT) technique to derive layer pressures. Results were used in a 3D simulation study showing that layer pressure differentials were controlled by offtake redistribution and could be sustained only if vertical permeabilities in siltstone/shale layers were extremely low. Units permeabilities in siltstone/shale layers were extremely low. Units in undrained flank blocks could be under depleted by as much as 10 MPa and drilling these blocks would increase developed reserves. Introduction The Ameland field, operated by Nederlandse Aardolie Mij. B.V. (NAM) for Energie Beheer Nederland B.V. (EBN) and Mobil Producing Netherlands Inc., is the third-largest gas field in the Netherlands, with gas initially in place(GIIP) of about 58 ร 10 m . The gas is produced from eight wells at two separate sites: one offshore and one onshore Ameland island (Fig. 1). Ameland reservoirs are part of the Rotliegend Slochteren Upper (ROSLU) sandstone formation, which has a 90- to 120-m gross thickness at 3200 to 3500 m deep. The reservoir initially was over- pressured by 20 MPa, but now is depleted to an average pressure of pressured by 20 MPa, but now is depleted to an average pressure of 31 MPa. The Rotliegendes mud/silt/sandstone sequence in the AmelandEast field can be subdivided into six distinct reservoir units: four contain mainly fine-grained sandstones and two contain mainly tight siltstones (Fig.2). The Ameland East field is the largest of a group of four fields separated by east/west-trending faults. To date, only the Ameland East field has been developed. This field is divided laterally into six main, southward-dipping fault-bounded blocks (Fig. 3). Most Ameland East field production comes from wells in the highly productive Central Blocks E15 and E11. Well productivity, at 5-MPa drawdown, ranges from 3.5 to 5.0 ร 10 m /d productivity, at 5-MPadrawdown, ranges from 3.5 to 5.0 ร 10 m /d in the central blocks to 0.3 to 1.5ร 106 m /d in flank blocks. Ameland Development Strategy In the first 4 years of production, the contractual capacity of the Amelandfield could be maintained with wells drilled only in the highly productive central blocks. It was assumed initially that the connectivity of reserves in flank blocks was adequate to ensure effective drainage toward the pressure sink in the central area. The reservoir performance trend increasingly shed doubt on this assumption because it indicated that material-balance GIIP was lower substantially than the volumetric GIIP. With the progressive decline in reservoir pressure and well producibility, a strategy had to be devised to position future producibility, a strategy had to be devised to position future wells needed to maintain production capacity. The economics of drilling less-productive, high-outstep wells on the flanks had to be weighed against the potential reduction in ultimate recovery resulting from poor flank depletion when only central drainage is relied on. The central issue was the degree of flank connectivity and differential depletion, not only laterally on a blockscale, but also vertically on a per-unit basis. From static gradient surveys, the maximum differential pressure between the drained blocks was estimated at2.5 MPa. However, fault plane sections based on 3D seismic, illustrating unitjuxtaposition, showed that locally, individual units in Flank Blocks E12, E14, E21, and E22 could be connected poorly or isolated from units in the drainedblocks (Fig. 4). Data on individual unit pressures in wells were needed to firm and refine the existing 2D reservoir model before the optimum development strategy was chosen. The MLT technique was selected as the most cost-effective way to obtain these unit pressures. Multilayer Well Testing Two wells were selected for MLT: Well AME 105, the only producer in BlockE21 in the western flank of the field, and Well AME 104. in the middle of Block El 1. Each well was tested as a five-layer system, the objective being to determine individual layer pressures, permeabilities, and Darcy and non-Darcy skins in producing pressures, permeabilities, and Darcy and non-Darcy skins in producing Layers 1, 3, and 5, and if possible, vertical permeabilities in the shale Layers 2 and 4. The layered-reservoir test consists of one transient(typically 5 hours) per producing layer, with the production logging too]stationed above each layer for one production logging too] stationed above each layer for one transient. Selective Inflow Performance. Fig. 5 shows the pressure and spinner data obtained from the test on Well AME 105, with the tool above the top layer for Transient 1 (highest rate), above Layer 3 for the lowest rate, and above the bottom layer for an intermediate rate. After each transient, a flow profile survey was run to determine the contribution to flow from each layer. If the layers are in pressure equilibrium and if inertial effects are insignificant, one would expect a doubling of flow rate to demand a doubling of flow rate from each layer. In a differentially depleted system, the relative contribution from each layer will vary with wellbore pressure. Fig. 6 shows the selective inflow performance, or layer-by-layer inflow performance relationship performance, or layer-by-layer inflow performance relationship (IPR) obtained from the profiles. The solid line represents the total system IPR for Well AME 105, and each of the other lines represents the response of one of the layers. If flowrates were highly turbulence-restricted, the curves would drop at the lowerend, but in this case, they are almost straight lines. The intercept of each curve with the zero-flow line represents the layer pressure, ignoring transient effects in the data. A difference of about 12 MPa existed between Layers 1 and5. The almost vertical line for Layer 3 illustrates poor productivity from this layer and introduces a large uncertainty into the intercept. Fig. 7 shows the layer IPR curves obtained for Well AME 104, with a 9-MPa pressure difference between Layer 5 and the two other layers. Sequential Convolution. The next step is the sequential convolution technique, where each transient is analyzed as a subset of the whole system. With the tool stationed above the bottom layer. the spinner responds only to flow to or from Layer 5, and convolution analysis of this data set is equivalent to a test on the bottom layer. Analysis of the data acquired above Layer 3 will give results for the two-layer system below the tool, from which Layer 3 results can be extracted if we have Layer 5 results; etc. SPEFE P. 5
Summary. Impulse activation is a new oxygen-activation technique developedto detect vertical water flow and to provide a quantitative measure of waterflow velocity and flow rate. Flow-loop measurements made over a wide range ofwater velocities are in good agreement with theoretical predictions. Measurements of up- and downward channel flow were made at the predictions. Measurements of up- and downward channel flow were made at the U.S. Environmental Protection Agency (EPA) leak test well in Ada. OK. to demonstratethe technique in a controlled environment and to confirm that EPA requirementshave been met. A major advantage of this method over previous procedures isthat a measurement in a known zero-flow zone is not previous procedures is thata measurement in a known zero-flow zone is not required. The impulse-activationtechnique has improved sensitivity to both low and high flow rates. In the EPAleak test well, the technique successfully discriminated between 0- and1.4-ft/min flow conditions. The lowest quantified velocity was 1.8 ft/min or 10BWPD, significantly below the EPA requirement of 3 ft/min. The upper limit ofdetection has not been determined but exceeds 137 ft/min. The water flow log(WFL.sM) measurement uses the impulse-activation technique and a Dual-Burst.thermal-decay-time (TDTSM) tool to detect water flow behind casing. Animportant application for this measurement is testing for fluid migration inthe wellbore as part of the mechanical integrity testing process for Class 1 and f1 disposal wells. The new oxygen-activation measurement was used innumerous production well. to identify the presence of water flow behind casing. Additional applications include the identification of open fractures inhorizontal wells and the quantification of water flow in the tubing/casingannulus in injection and production wells. production wells. Introduction Vertical movement of water in channels within the casing/borehole annulus Isa problem in oilfield production and injection operations. Such channels canprovide an undesirable communication path between formations of differentpressures and reduce well efficient cy. Particularly undesirable is the upwardchanneling of such fluids as oilfield brines into shallow freshwater aquifersthat are a source of drinking water. Methods to detect and locate fluid flowbehind well casing use temperature, acoustic noise. and radioactive-tracerlogs. Combinations of these logs have successfully located water movement. butinterpretation of the log data is often difficult. The oxygen-activation log isan alternative method specifically for detecting water flow. Use of theoxygen-activation technique to measure water flow in boreholes is well known. Recent works address its specific use for measuring water flow behind casing. The major draw-back of the traditional method is the requirement that acalibration measurement be made in a well's zero-flow zone Selection of thiszone is often difficult and sometimes impossible. The improper selection orunavailability of a "known" zero-flow zone can lead to incorrectchannel identification. resulting in the false indication or masking of flow. The WFL uses the impulse-activation technique and does not require ameasurement in a known zero-flow zone. Water flow is detected with near and far TDT detectors and a gamma ray detector located 15 It from the neutron source(Fig. 1). The WFL measurement has a wider range of flow sensitivity and agreater depth of Investigation than the traditional method. Fast Neutron Activation of Oxygen The presence of oxygen is determined by detecting gamma rays emittedfollowing the fast neutron activation of oxygen nuclei: ...............................................(1) Past neutrons. with energies is greater than 10 MeV. are used to activate Past neutrons. with energies is greater than 10 MeV. are used to activateoxygen nuclei to produce a radioactive isotope of nitrogen. Radioactivenitrogen nuclei decay by B- emission with a half-life of 7.13 seconds. High-energy gamma rays are emitted after decay of 16N. the most important beingthe 6. 13-MeV gamma ray emitted in 69% of the 16N decays. The threshold neutronenergy for the O(n.p) reaction is 10.2 MeV, which is ideally suited to boreholeneutron generators that produce 14-MeV neutrons. Because of its high energy.the 6. 13-MeV gamma ray can penetrate several inches through such typicalwellbore materials as the borehole fluid. tubing, casings, and cement. Traditional Method for Measuring Water Flow Behind Casing The traditional method for measuring water flow behind casing using oxygenactivation is a steady-state method. A station measurement is made with acontinuously pulsing neutron source, and oxygen-activation gamma rays arecounted when the flowing water passes two detectors at different spaces fromthe source. As the passes two detectors at different spaces from the source. Asthe water travels the distance between detectors. The gamma ray intensitydecays exponentially by an amount determined by the travel time. Travel time isdetermined by the detector spacing and the water velocity. Consequently. forfixed detector spacing. the ratio of detector count rates is an exponentialfunction of water velocity. In practice. stationary oxygen in the borehole, cement annulus. and formation is also activated. Thus. the traditional methodrequires a calibration measurement in a known zero-flow zone. Zero-flow-zonecount rates are subtracted from subsequent measurements to compute the netcount rate from flowing oxygen. Because the flow signal can be small at lowflow rates. it is critical to the tradiional measurement to know the correctzero-flow signal. An incorrect signal can be caused by misidentification of asupposed zero-flow zone or by use of a zero-flow zone that does not match theenvironmental conditions of the test zone. Important conditions includeborehole fluid and geometry; tubing; casing and cementing materials; and suchformation parameters as lithology. porosity, and water saturation. porosity, and water saturation. In the traditional method. the neutron source is operatedin a coninuous pulsing mode with a neutrons-off period allowed several timesper second to measure the oxygen-activated count rate. After about 40 seconds(six half-lives), the oxygen count rate at both detectors reaches asteady-state value. Therefore. data acquisition over the next several minutesprovides a measurement of the steadystate activated oxygen signal at bothdetectors. Plow is detected if steady-state values exceed the calibrationvalues from the zeroflow zone, and the flow velocity is determined from theratio of the corrected signals. SPEFE P. 334
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