Permeability-thickness Product Research Articles

Flowback Test Analyses at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) Site

In 2017 and 2019, injection testing was carried out in three zones in a vertical well in granite at the Frontier Observatory for Research in Geothermal Energy site near Milford, Utah, USA. In several injection cycles, flowback was implemented rather than shut-in. The goal was to explore an alternative to prolonged shut-in periods for inferring closure stress, formation compressibility, and formation permeability (permeability thickness product). The flowback procedures involved a cyclic flowback/shut-in, while pressure decreased. The flowback data are presented, and analyses are shown. The inferred closure stress(es) from flowback analyses are lower than for equivalent injection cycles that were strictly shut-in. Relatively high formation compressibility obtained from the flowback analyses indicates an extensive, fractured system. This study also includes numerical simulation of the flowback events. The numerical model shows that the rebound pressure is not necessarily the lower bound of the minimum principal stress. The signature of stiffness change can be identified as the process when the depletion mainly transitions from hydraulic fracture to natural fractures from numerical analysis. Overall, flowback potentially has advantages over shut-in because of the reduced time to closure.

A comprehensive analysis of transient pressure and rate data from CO2 storage projects in a depleted pinnacle reef oil field complex, Michigan, USA

Pressure and rate data are commonly recorded as part of a basic monitoring program in CCS projects. This paper discusses the application of multiple analytical techniques to interpret pressure and rate transient data from CO2 injection and storage operations. The techniques of interest, i.e., injection-falloff analysis, injectivity/productivity index analysis and pressure pulse arrival time analysis, are commonly used in the oil and gas industry to assess reservoir properties, but not well known in the CCS literature (especially the last two). Injection-falloff analysis involves log-log pressure derivative plotting for the falloff data and history-matching of the entire injection-falloff sequence to determine permeability. In the injectivity/productivity index analysis, rate-normalized pressure buildup is plotted against material balance time or ratio of cumulative injection to injection rate to determine the injectivity index (ratio of injection rate to stabilized pressure buildup) which can be related to the permeability-thickness product. The arrival time analysis identifies the arrival of a pressure disturbance (∼0.1 psi change from ambient) to determine the hydraulic diffusivity from which permeability can be estimated. The applicability of these techniques is demonstrated via illustrative examples from multiple wells in different pinnacle carbonate reefs undergoing CO2-EOR in Northern Michigan. The paper ends with a discussion of the relative merits of each interpretive technique, as well as recommendations that could be useful for other field projects.

An Operations Perspective on Injectivity and Capacity

Injectivity and capacity are two of the most important criteria of a CO2 storage site’s screening and selection process. A geologic formation can be characterized directly to quantify injectivity and capacity via the permeability-thickness and porosity- thickness products, respectively. After a project starts, the importance of each to the project is slightly different. Maintaining injection rate is one primary challenge during active injection operations, while the long-term storage capacity is one primary challenge to the storage project. For specific projects, the daily injection rate of CO2 and the ultimate storage quantity desired are based on the capture and compression facility, and the CO2 source is the driver to determine the mandatory qualifications of a site. Injectivity is defined as the ratio of the injection rate to the pressure change between the well and the storage zone, which is proportional to the permeability-thickness product. The initial start-up and subsequent start-ups of CO2 injection following short and extended shut-in periods are ideal times for multirate CO2 injection. These injection tests performed periodically can show injectivity behavior over longer periods of time so that the trends of the injection interval response can be analyzed and projected for longer terms when a stimulation or another sub-interval perforation may be required for injection. Because rate and pressure are generally direct measurements, injectivity-time, rate-pressure-time, and rate-pressure relationships can be used to diagnose trends in injection operations that are not apparent from injection rate alone. Capacity is defined as a quantity (mass or volume) of CO2 that can be injected and stored in a specific geologic formation from a specific injection project; it is proportional to porosity-thickness product. While permeability and capillary pressure are not part of the capacity calculation, both properties determine the accessibility of the porosity to injected CO2, hence the part of the pore space that can be used for storage. Furthermore, local geologic heterogeneity and architecture will strongly influence petrophysical flow properties and determine the plume size and shape. Storage efficiency has been used to define the fraction of the pore volume (or bulk volume) in which CO2 can be stored. It includes geologic (e.g. ratio of net to gross thickness), macroscopic (e.g. gravity), and microscopic (e.g. saturation) terms. It is relatively simple to quantify capacity if the location and distribution of CO2 is not required; however, if approximate dimensions of CO2 plume is necessary, it is very difficult to quantify confidently capacity. Prior to CO2 injection, statistical methods, numerical simulation, and a limited number of analytical methods are available. During injection, the most direct measurement is cased hole logging (e.g. neutron capture logs), which only measures very near wellbore CO2 saturation above a threshold saturation (e.g. 5%). Once the CO2 plume area, thickness, and saturation are adequate to make a detectable seismic contrast, a seismic survey may be helpful, but it detects only the thicker and higher CO2 saturation parts of the plume. Real-time analyses of injectivity and capacity during CO2 injection can provide operators with information necessary to plan for contingencies that increase certainty and meet the CO2 project goals. During site screening and selection, project risk can be reduced, but only after actual CO2 injection can these properties be more convincingly estimated. Injection operation results and observations, from the US Department of Energy sponsored Illinois Basin Decatur Project at Decatur, Illinois, USA, are used to demonstrate changes in injectivity and capacity through time and their influence on operations.

Formation pressure and fluid flow measurements in marine gas hydrate reservoirs, NGHP-02 expedition, offshore India

Abstract Open Hole Modular Dynamic Testing (MDT) measurements were conducted in a gas hydrate-bearing sand-rich reservoir offshore India during the National Gas Hydrate Program 02 (NGHP-02) Expedition. The primary goal of this test was to obtain effective reservoir petrophysical properties in the presence of gas hydrates. The test plan included a series of pre-hydrate dissociation flow and build-up (shut-in) tests, and an attempt to dissociate gas hydrate in a sand-rich reservoir by depressurization to collect formation fluid samples and to further characterize in situ gas hydrate stability conditions. Schlumberger's wireline MDT tool was used in a dual-packer configuration to isolate the formation being tested. This paper presents the results of the open hole MDT measurements that were conducted in Hole NGHP-02-23-C in Krishna-Godavari Basin at a water depth of 2553.5 m. The MDT dual packer test was conducted in 27 cm (10.63 in) diameter open hole section of the borehole within a 1-m interval isolated between two inflatable packers with the midpoint of the test interval at 2853.0 m below rig floor (mbrf) (271.0 m below sea floor (mbsf)). This was the first gas hydrate MDT test ever conducted in ultradeep water to characterize a gas hydrate reservoir system. Pre-hydrate dissociation testing was performed with a drawdown period (depressurization) of 20 min followed by a build-up (shut-in) of 20 min. The measured formation pressure was 4090.7 psia and the formation fluid (i.e., water) mobility was calculated at 1.98 mD/cP. During the second dissociation phase of the same test a maximum pressure drawdown of 840 psia was achieved; however, falling short of the 1120 psia drawdown required for dissociation. During the dissociation test the flow line pressure stabilized at a flowing pressure of 3250 psia which can be attributed to the relatively high mobility of the free water phase in the hydrate-bearing reservoir. Good quality formation pressure and near well bore mobility data was acquired that yielded a “high confidence” reservoir effective radial permeability-thickness product of 0.2 mD.m (or a horizontal effective permeability of 0.1 mD assuming a reservoir thicknees of 1.8 m) using pressure transient analysis (radial flow regime was achieved) despite unstable borehole conditions and complex operations in these shallow unconsolidated sedimentary sections.

Guidelines to define the critical injection flow rate to avoid formation damage during slurry injection into high permeability sandstone

In a slurry injection application, the goal is to inject high solid content fluids (up to 25%). To accomplish this without plugging the near-wellbore pore space, the fracture is created using a pad of clean fluid. Once the fracture is open, the slurry is introduced to the formation. In some cases, where the formation has a high permeability-thickness product (k × H), a high injection flow rate is needed to open up the fracture with clean fluids. Most disposal wells do not have large enough pumps to provide high enough flow rates in these circumstances.A combination of a lack of geomechanical understanding combined with poor injection or facility design leads some operators to create high formation damage around the wellbores in slurry injection applications by injecting slurry at flow rates which are insufficient to open fractures. When solids-laden fluid slurries are injected under a matrix flow regime, suspended solids will plug the near-wellbore pore throats and will form a filter cake layer at the formation face, causing the injection pressure to gradually increase. At the point where the injection pressure exceeds the formation fracture pressure, the formation will finally fracture. However, the near-wellbore filter cake remains a factor in future injection and leakoff characteristics. Moreover, the damage causes injection pressure to build up rapidly, facilitating the creation of short fractures which tend to cause near-wellbore stresses to increase more rapidly for a given amount of solid deposition than is the case with longer fractures.Case studies have been presented in this paper which evaluates such slurry injection wells. Based on the data analyzed in this study, inducing the fracture with solids-laden slurry rather than with clean fluid by causes the injection pressure to continuously increase, ultimately leading to significantly reduced formation capacity. Recommendations are presented as well for how to avoid this condition even if the pumps do not have the capacity to provide the required injection flow rate using clean fluid. One such solution is to add a viscosifier to the clean pad fluid to raise the fluid viscosity which enables the creation of a hydraulic fracture at lower flow rate.

Analyzing the Performance of Closed Reservoirs Following CO2 Injection in CCUS Projects

This paper discusses the use of a 2-D numerical model representing a typical depleted pinnacle reef reservoir to generate synthetic data for multiple CO2 injection periods after a prolonged period of oil and gas production. The data are analyzed with conventional pressure-transient analysis and injectivity-index approaches from petroleum reservoir engineering practice.Pressure falloff data from multiple shut-in periods, with and without boundary effects, indicate that the system response is similar to that of a composite reservoir with different total mobility and total compressibility values in the inner (CO2-rich) and outer (CO2-free) regions. The total mobility of the inner zone can be approximated by the total mobility of the gas phase in the vicinity of the CO2-oil front, while the total mobility of the outer zone corresponds to the total mobility of the oil phase in the undisturbed region.The injectivity index, calculated as injection rate divided by the pressure buildup from reference conditions, yields a quasi-stable value during the transient period which can be correlated to the permeability-thickness product of the injection zone. During the boundary-dominated (pseudo-steady-state) period, a flowing material balance plot can be utilized to determine an apparent injectivity index, which is higher than the true injectivity index because of multi-phase skin effects.

Characterization of interlayer air permeability of thermoplastic prepreg stacks

An important mechanism for void air removal during oven vacuum bag processing for thermoplastic composites relies on void air flow to the part perimeters through the permeable pathways created by the rough surfaces of two adjacent prepreg layers. In this paper, the interlayer air permeability of AS4/APC2 carbon poly (ether ether ketone) thermoplastic prepreg was investigated before and after oven vacuum bag processing conditions. The permeability thickness product was measured with an experimental set-up and data reduced based on one-dimensional Darcy’s flow. The interlayer permeability exhibit directional dependency and are uniquely determined by the angle between two adjacent prepreg layers. Before oven vacuum bag processing, the principal permeability thickness products for lay-ups with included angle of 0°, 30°, 60°, and 90° were determined. Good agreement was achieved between the rotation matrix predicted permeability thickness products and the measured results. During processing, when temperature is above resin glass transition and below melting, the permeability of 0°/0° and 90°/90° interlayers reduces dramatically with increasing temperature and dwell time. For the 0°/90° interlayer, only a slight reduction compared to the room temperature baseline was obtained for temperature ramps up to 300℃ and dwell time up to 8 h at 240℃. The changes of the surfaces roughness were correlated to the reduction of measured permeability. The 0°/90° interlayer surface shows the evidence of fiber–fiber contact that limits the contact between layers and prevents significant drop of permeability during processing. Off-axis stacking sequences with fiber–fiber contact are advantageous for oven vacuum bag processing of large thermoplastic composite parts.

Probing diagnostic fracture injection tests in unconventional reservoirs

Abstract Diagnostic fracture injection tests (DFIT) are commonly used to characterize stress and reservoir properties in unconventional reservoirs. Although simple in concept, interpreting DFIT results can be difficult because several factors can cause results to deviate from ideal DFIT behavior. Some examples of non-ideal DFIT behavior include steep pressure declines after shut-in, absence of pseudo-linear and pseudo-radial flow, and excessive storage indications. Such deviations from ideal DFIT behavior challenge our ability to estimate formation properties reliably. Potential drivers of non-ideal behavior include heterogeneous rock properties, complex rock/fluid interaction, multiphase effects, and natural fractures. The objective of this study is to investigate how these factors can impact DFIT results and interpretations. A comprehensive approach was taken using a combination of pressure transient analysis, frac modeling, analytical leak-off modeling, and detailed numerical simulation of DFIT behavior. The application was for a horizontal well, completed in a shale gas reservoir, which included an actual field DFIT. Detailed modeling included full wellbore transients and storage, hydraulic behavior through induced fractures, as well as complex interactions between rock, fluids, and natural fractures. It was determined that the actual DFIT showed indications of a complex network created by the pump-in. Closure pressure estimates were found to be reliable, between the simulation cases and DFIT analysis. However, a consistency check on initial reservoir pressure had to be used to obtain reasonable estimates compared to the simulation input. Finally, estimates of reservoir conductivity were highly uncertain compared to the actual simulation inputs. Furthermore, the actual DFIT estimates of reservoir pressure and conductivity were found to be overoptimistic. In fact, the estimated ultimate recovery using DFIT-based permeability-thickness product turned out to be more than twice the estimated ultimate recovery using the integrated core, log, and a pressure-buildup test.

Properties of a Natural Fracture and Its Skins From Reservoir Well Tests

Summary Two well tests are described that are aimed at the in-situ determination of the flow capacity (permeability-thickness product) of a natural fracture and the flow resistance of its skins at the boundaries with the reservoir matrix. Fracture skins tend to disperse flow, thus affecting the distribution of tracers in reservoir tests and contaminants and trace elements in aquifers. We are unaware of any other analytical procedure aimed at obtaining the properties of a natural fracture and its skins from subsurface measurements. Neither well test has been implemented. The well tests are modeled after previously reported analytical expressions for the transient pressure distributions in a three-region composite reservoir in a uniform-thickness reservoir in which (1) the natural fracture is represented by a thin middle region of relatively high permeability, (2) the pressure disturbance is caused by producing from a short interval in one of the outer regions, and (3) the response is measured relatively near the fracture. The source and sensor may be on the same side or on opposite sides of the fracture, distinguishing the two tests. Visualizing special completions in a horizontal well intersecting a natural fracture normally, pressure responses are given for both tests for a wide range of fracture/matrix permeability ratios and skin flow resistances for a source 190 ft from the fracture and 10 ft from the sensor and on either side of the fracture, both at the midplane of the reservoir. A simple graphical procedure, not intended to replace history matching or regression where field data are available, illustrates how the two unknowns—permeability-thickness product of a natural fracture and the flow resistance of its skins—may be estimated from two representative values of an assumed measured pressure response.

Evaluation of Thin Film Noise Suppressor Applied to Noise Emulator Chip Implemented in 65 nm CMOS Technology

This paper reports the shielding effect of soft magnetic film as a thin film noise suppressor applied to a test chip implemented in 65 nm seven metal CMOS technology. This test chip is equipped with a noise generator circuit. The 0.2-1- μm-thick magnetic films, which are integrated with polyimide substrates, are mounted onto the noise generator circuit in the test chip, and 2-μm-thick magnetic film is directly integrated to the passivation of the test chip. These films are deposited by RF magnetron spattering. The shield effect is evaluated by magnetic near-field measurement using planar shielded loop probe and 3-D full-wave electromagnetic field simulation. As a result, we successfully demonstrate a shield effect of 7.7 dB at a crock frequency of 200 MHz with 2-μ m-thick CoZrNb film. Furthermore, the result of the thickness dependence of the shielding effect revealed that a permeability-thickness product (μr × tm) of 1 950 μ m is required as the design target for obtaining 10 dB suppression.

Identification and Characterization of High-Conductive Layers in Waterfloods

Summary This study expands upon the use of modified-Hall analysis (MHA) to discern the characteristics of a high-permeability channel. Briefly, the modified-Hall plot uses three curves involving improved Hall-integral (H-I) and the two derivatives, analytic and numeric. Ordinarily, the derivative curves overlay on the integral curve during matrix injection, but separate lower when fracturing occurs. This work presents a method to identify and characterize high-conductive layers or channels between injector and producer pairs with the MHA. The distance separating the integral and derivative curves provides the required information to quantify channel properties. A simple analytical solution is presented for transforming the separation distance into channel permeabilitythickness product. The analytic derivative is based on the radial-flow-pattern assumption and the numeric derivative is correlated to the pressure response. Therefore, a comparison of these two curves reveals clues about the maturity of a waterflood at a given time. Several simulated examples verified the channel-property-estimation algorithm and identified the distinctive derivative signatures for channeling and fracturing situations. This method is also useful for identification of wormhole propagation during sand production in unconsolidated formations.

Evaluating Confidence Intervals in Well-Test-Interpretation Results

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 113888, "Evaluation of Confidence Intervals in Well-Test- Interpretation Results," by A.C. Azi, SPE, and A. Gbo, SPE, Imperial College; T. Whittle, SPE, Baker Atlas; and A.C. Gringarten, SPE, Imperial College, prepared for the 2008 SPE Europec/ EAGE Annual Conference and Exhibition, Rome, 9-12 June. The paper has not been peer reviewed. Uncertainty in well-test analysis results from errors in pressure and rate measurements; from uncertainties in basic well and reservoir parameters; from the quality of the match with the interpretation model; and from the nonuniqueness of the interpretation model. Yet, well-test-analysis results often are reported as unique values, with unrealistic precision. A practical method is presented to determine error bounds in well-test analysis. An application with well tests from an oil reservoir and a gas-condensate reservoir in the North Sea evaluates typical error bounds for the most common parameters. Introduction Uncertainty in well-test analysis was made worse by the use of hand-held calculators and, later on, computers and well-test-interpretation software for performing well-test-analysis calculations because engineers, students, and professionals alike seem to accept that because the tools they use display eight decimal places, all eight places are accurate. Consequently, distances to boundaries often are reported with a resolution of tenths of a foot, skin values are reported with two decimal digits, and permeabilities greater than 100 md are reported to within 0.1 md (i.e., with resolutions finer than 0.1%). It has been pointed out that the results of a well-test interpretation could never be more accurate than the values of applicable rock and fluid properties. An interactive, graphical method can describe the objective-function (a measure of the difference between model and data) behavior around the optimal solution to provide the interpreter with a range of solutions instead of a single value. The main objective of this paper is to provide uncertainty ranges derived from several tests in different reservoirs. Method This method uses four steps. It provides the uncertainty in well-test results associated with a specific match to a specific model as well as uncertainties in well- and reservoir-input parameters and in the match parameters. The uncertainty associated with the choice of model (which could imply a much larger uncertainty in results) is not taken into account. Step 1 (Fig. 1): Well-Test Analysis. The analysis yields values of match parameters [e.g., pressure match; time match; curve match, (CDe2s)match; and distance to the fault, dD] and a measure of the match quality expressed as a standard deviation. The equations defining the match parameters are expressed in terms of well- and reservoir-input data [i.e., flow rate, formation volume factor (FVF); viscosity; total compressibility; reservoir thickness, h; porosity; and wellbore radius] and they provide the analysis results (e.g., permeability-thickness product, kh; permeability, k; skin effect, S; wellbore-storage coefficient, C; and distance to the boundary, d).

HP/HT Gas-Condensate Well Testing for the Shell Onyx SW Prospect

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 108665, "HP/HT Gas- Condensate Well Testing for Shell's Onyx SW Prospect," by Arild Fossa, Expro; Derek MacKenzie, SPE, Norske Shell; Odd Steinveg and Eric Henderson, Expro; and Bart van den Bosch, SPE, Halliburton/Shell, prepared for the 2007 Offshore Europe, Aberdeen, 4–7 September. Complex data gathering occurs over a shorter time with much stricter environmental and safety constraints than ever before. Coupled with increased needs for more-accurate reservoir data for prospect evaluation, emphasis is placed on upfront planning and improved technical performance together with extensive use of advanced fluid-data-gathering methodologies. The latest technologies in testing gas-condensate wells were used on this job. Experiences were used later as the basis for other gas-condensate prospects, including those in the Russian sector of the Barents Sea. Introduction Onyx Southwest (SW) exploration Well 6406/9–1 was the second well drilled under License PL 255 offshore Norway. The first well, Well 6406/5–1 in the Tott East prospect, was drilled in 2002 to intersect sands of the Middle-to-Lower Jurassic Garn, Ile, and Tofte formations. Well 6406/9–1, was planned as a vertical exploration well for a possible high-pressure/high-temperature (HP/HT) regime. Although the HP/HT conditions were marginal, the test was designed and executed as if under full HP/HT conditions. Maximum surface pressure with reservoir fluids to surface was considered to be less than 690 bar. Bottomhole static temperatures were anticipated to be in excess of 150°C. The main objective was to investigate the stacked Ile, Ror/Tofte, and Tilje formations by conducting a multizone drillstem test (DST), with each interval being tested separately. Testing of two zones with a third was planned as a contingency to cover formations of interest. Results from well logging narrowed the selection to a two-zone DST. Test Objectives For the Onyx SW exploration-well formations, the primary test objectives for each reservoir were to assess the productivity and to obtain representative fluid samples. Obtaining reservoir pressure and temperature; determining skin and permeability-thickness product, kh; and identifying possible reservoir boundaries and heterogeneities for the formations were secondary objectives of the well tests. These secondary objectives would aid safety and equipment selection for future wells, as well as provide the starting point for further reservoir analysis. The kh and skin could not be attained satisfactorily for HP/HT wells in any other way because alternative methods have poor performance under such well conditions. The kh and skin parameters were selected to further aid analytical reservoir-simulation work and to enable improved use of the productivity data. Detection of possible reservoir boundaries and heterogeneities was included as a secondary target for planning a future field-drainage strategy. To achieve the test objectives, a set of special requirements was established to obtain the desired data quality. These requirements were downhole shut-in, testing the well with seawater as the packer fluid, and use of downhole memory gauges and single-phase sampling.

Permeability From Production Logs—Method and Application

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Abstract Estimating effective permeability at the reservoir scale has been a long-standing challenge in carbonate fields. The carbonate depositional and diagenetic history can be very complex, which can lead to permeability that is difficult to characterize. Vuggy or fractured intervals can have permeability significantly higher than the matrix permeability measured in core plugs. This "excess permeability" may control reservoir flow paths but is difficult or impossible to predict from static well-log transforms that are calibrated to matrix permeability. In the Tengiz field, a giant carbonate reservoir in western Kazakhstan, a method has been developed to calculate apparent permeability on the basis of flow rate from production-logging tools (PLTs). Incorporating this flow-calibrated permeability into the Earth model offers an elegant solution to the long-standing problem of the best method to incorporate dynamic PLT data into a reservoir model. Recently, a reservoir model built with apparent permeability resulted in more-realistic heterogeneity and a step-change improvement over previous methods in which only static log-based permeability transforms were used to populate the Earth model. Fewer changes were required to calibrate the full-field reservoir model. History matching to pulse tests showed that this model has a much-improved prediction of the interwell connectivity. Models containing apparent-permeability data have provided higher-confidence estimates of the future movement of gas injection from the Tengiz platform. The apparent permeability is calculated by solving Darcy's law on an interval basis, using our knowledge of flowing and static pressures as input along with well, reservoir, and fluid properties, and then calibrating with the pressure-buildup transient permeability-thickness product, kh. Accuracy of the method is enhanced by the derivation of coarse-scale zonal layer pressures with multirate PLTs. Selecting an appropriate skin factor to use in the calculation is important. The acid effect on pulsed-neutron-capture (PNC) logs works well in Tengiz and has been helpful in addressing this problem. Introduction The fundamental building blocks of a reservoir model are porosity, permeability, and fluid saturation. Porosity and fluid saturation can be computed from wireline logs with reasonable confidence, but often, the same confidence is not possible for permeability. Permeability can be measured directly from core material or determined with well tests by use of pressure-transient tests (PTTs), pulse tests between wells, and wireline formation tests. Scale differences in these sources of permeability data complicate the permeability estimation in a reservoir model (Al-Henshiri et al. 2005; Ahmed et al. 1991). In most reservoirs, the amount of core available for direct permeability measurement is limited, and permeability estimates usually are made by proxy by use of wireline-log responses. The science of permeability prediction has evolved into a high degree of sophistication, with each additional level resulting in an incremental gain in predictive accuracy (Skalinski and Sullivan 2001). Despite the available sophisticated tools, permeability prediction in carbonates remains problematic. The widely varying pore structures (Lucia 1995) and their potential lack of connectivity result in a highly variable porosity/permeability relationship. Vuggy porosity and fractures, if they are connected, can result in extremely high layer flow rates or very low rates, if not connected, for the same value of porosity.

Value of Injection Testing as an Alternative to Conventional Well Testing: Field Experience in a Sour-Oil Reservoir

Summary Environmental constraints and high costs, especially offshore, are making conventional-well testing less and less feasible and accepted by the public administration. New options were thoroughly evaluated to find a viable alternative to standard production tests for characterizing the well productivity without surface production. An accurate investigation demonstrated that injection tests could provide all the information needed to calculate the well productivity at reasonably low costs and with a good degree of reliability. On the basis of the results of laboratory and field pilot tests, it was proved that injectivity tests could be applied successfully to a real sour-oil field. Laboratory tests proved that brine could be a suitable injection fluid because there were no compatibility problems with the oil and the reservoir rock. It was verified that the interpretation of the pressure transients should be referred to the falloff period rather than to the injection phase. The formation permeability-thickness product (kh) could be identified correctly from the pressure-derivative analysis only if multiphase flow was assumed. The total skin value could also be obtained from the test interpretation. The total skin comprises two components: a mechanical component resulting from permeability damage and a biphase component resulting from fluid interaction in the reservoir. Except for a limited number of cases, the biphase skin can be evaluated only with numerical well testing, provided that the fluid relative permeability curves are available. It was also demonstrated that the biphase component depends mainly on the injection rate but is independent of the formation permeability. Then, the well-known transient equation was applied to determine the well productivity index (PI) based on the kh and the mechanical skin. PI values calculated from injection tests compared satisfactorily with PI values measured from six drillstem tests (DSTs) performed on appraisal wells.

Exploring Reservoir Engineering Aspects of Completion in Gas/Condensate Reservoirs: West African Examples

Summary This paper explores multiple completion options in gas/condensate reservoirs with compositional simulations. Besides intelligent-well completion (IWC), options included commingling two reservoirs of contrasting conductivity (permeability-thickness product) and selectively perforating zones or reservoirs to offset the permeability contrast. At the outset, a value-of-information exercise suggested probing downhole sensing and completion issues in a stacked-reservoir situation. The ultimate objective of this study was to ascertain economic completion strategy so that depletion of reservoirs occurs evenly at the project's termination. Single-well compositional simulations formed the backbone for our evaluation of three completion options. Each reservoir was characterized by history matching drillstem tests (DSTs). Experimental design (ED) reduced the large number of simulation runs to a manageable few for probabilistic forecasting. Comparison of three options suggested that all of them nearly produced the desired results of maximum liquid recovery despite a 10-fold difference in permeability between the two horizons. Results further showed that condensate banking was a nonissue in this high-kh system of reservoirs as far as the gas deliverability is concerned. In other words, although 40 to 60% degradation in the gas productivity index (PI) occurred, gas deliverability remained intact. In contrast, both the liquid PI and rate declined with time owing to phase-behavior and relative permeability issues. Finally, we learned that the net income generated by IWC is no better than the specific-perforation completion (SPC).

96/05710 Paying for the future — Securing investment in Britain's oil and gas industry

This paper discusses the use of a 2-D numerical model representing a typical depleted pinnacle reef reservoir to generate synthetic data for multiple CO2 injection periods after a prolonged period of oil and gas production. The data are analyzed with conventional pressure-transient analysis and injectivity-index approaches from petroleum reservoir engineering practice.Pressure falloff data from multiple shut-in periods, with and without boundary effects, indicate that the system response is similar to that of a composite reservoir with different total mobility and total compressibility values in the inner (CO2-rich) and outer (CO2-free) regions. The total mobility of the inner zone can be approximated by the total mobility of the gas phase in the vicinity of the CO2-oil front, while the total mobility of the outer zone corresponds to the total mobility of the oil phase in the undisturbed region.The injectivity index, calculated as injection rate divided by the pressure buildup from reference conditions, yields a quasi-stable value during the transient period which can be correlated to the permeability-thickness product of the injection zone. During the boundary-dominated (pseudo-steady-state) period, a flowing material balance plot can be utilized to determine an apparent injectivity index, which is higher than the true injectivity index because of multi-phase skin effects.

Completion and Production Results From Alternate-Path Gravel-Packed Wells

Summary A successful gravel pack requires two things: perforations packed with gravel-pack sand and a completely packed annulus. Failure to obtain either one can result in low productivity and/or a sand-producing gravel pack. Alternate-path gravel packing ensures that the annulus will be completely packed and that all perforations taking fluid will be packed with gravel-pack sand. Alternate-path gravel packing has provided long and highly productive completions without any sand production. This paper presents completion data and production results from 39 wells completed with the alternate-path gravel-pack technique. The completion data include completion length, net perforations, carrier fluid, sand placement outside casing, workover fluid, and return rate during packing. Production results include qualitative discussion of all completions with quantitative results, including permeability-thickness product and skin on select completions.

Horizontal well case study under pattern waterflood. Investigation of horizontal well performance in a heterogenous carbonate oil reservoir.

The performance of two horizontal wells drilled in a major limestone oil reservoir in the Middle East was investigated. The wells were drilled to test the application of horizontal wells in the reservoir by replacing two watered out vertical wells.The reservoir is relatively thin (-45ft.) and highly heterogenous. The reservoir is characterised by significant vertical variation in horizontal permeability with the majority of the flow capacity situated in the botton 10-15% of the reservoir section. Furthermore, a thin, and possibly continuous, low vertical permeability dense calcified zone, caused by stylolitisation, has been suspected immediately above the high flow capacity formation.The Well A case is unique in that water breakthrough was observed in the vertical well, but to date, not in its replacement horizontal Well A (drilled in the upper half of the reservoir section). This is in spite of more than 24 months of production from Well A. This compares to the performance of the Well B replacement horizontal well in a nearby pattern where water production was recorded immediately after the well was brought on line.The performance of horizontal Wells A and B can be explained by examining the degree of vertical heterogeneity and layer segregation within the reservoir. The predicted shape and rate of advance of the water flood front in the Well A and B pattern element models can be successfully controlled using a combination of vertical layer heterogeneity and layer kv reduction. Specifically, it is layer permeability thickness product contrast and layer segregation that controls the shape of the advancing flood front. The greatest influence on well performance is observed when the vertical permeability of the dense calcified zone is drastically reduced.

Characterization of Tight Reservoirs

This paper gives methods to characterize tight gas reservoirs in sufficient detail to allow an engineer to make accurate long-range production forecasts. These forecasts are the bases for sound engineering and business decisions. Because of the complexity and variability of tight gas reservoirs, the authors can present only general procedures for developing reservoir descriptions. Accordingly, the authors illustrate a reservoir characterization method with three examples of successful tight gas reservoir studies. The procedures in these examples can be modified as needed for other specific formations or areas.