Fracture Closure Pressure Research Articles

Using the Q factor to detect closed microfractures

Fractures are ubiquitous within the subsurface and play an important role in the fluid flow, elasticity, and strength of rocks. Because they are essential to geologic systems such as hydrocarbon and geothermal systems, they need to be properly imaged and monitored. We used the spectral-ratio technique to measure the P-wave Q factor ([Formula: see text]) and the S-wave Q factor ([Formula: see text]) of dry and water-saturated crystalline rock samples that were thermally fractured by heating to 250, 450, 650, and 850°C. Increasing the temperature during thermal treatment produces an increased fracture density that is isotropically distributed. The samples were subjected to hydrostatic pressures up to the pressure at which all fractures are closed, and they were axially loaded to 25% of the failure strength. Axial loading of the samples further closes fractures that are oriented perpendicular to the loading direction, but it opens those that are oriented parallel and oblique to the loading direction. Attenuation measurements were made in the frequency range of 0.8 to 1.7 MHz. At the fracture closure pressure, the sample with the highest fracture density showed a reduction in [Formula: see text] and [Formula: see text] when compared to the sample with the lowest fracture density of 84% and 24%, respectively, under dry conditions and by 33% and 5%, respectively, under saturated conditions. The [Formula: see text] and [Formula: see text] increase as the samples were axially loaded. The increase is more pronounced in [Formula: see text] because it is less influenced by the opening of parallel and obliquely oriented fractures. The opening of these fractures mostly affects the propagation of the S-wave and therefore reduces the increase in [Formula: see text]. The results suggest that [Formula: see text] is very sensitive to fracture closure at intermediate and high effective mean stresses. We determine that [Formula: see text] is a useful measure of the fracture density even at high pressures at which fractures might be expected to be fully closed.

Automated pressure transient analysis: A cloud-based approach

Pressure transient analysis provides essential information to evaluate the dimensions of injection induced fractures, permeability damage near the wellbore, and pressure elevation in the injection horizon. For injection wells, shut-in data can be collected and analyzed after each injection cycle to evaluate the well injectivity and predict the well longevity. However, any interactive analysis of the pressure data could be subjective and time-consuming. In this study a novel cloud-based approach to automatically analyzing pressure data is presented, which aims to improve the reliability and efficiency of pressure transient analysis.There are two fundamental requirements for automated pressure transient analysis: 1) Pressure data needs to be automatically retrieved from field sites and fed to the analyzer; 2) The engineer can automatically select instantaneous shut-in pressure (ISIP), identify flow regimes, and determine the fracture closure point if any. To meet these requirements as well as to take advantage of cloud storage and computing technologies, a web-based application has been developed to pull real time injection data from any field sites and push it to a cloud database. A built-in pressure transient workflow has been also proposed to detect any stored or real-time pressure data and perform pressure analysis automatically if the required data is available.The automated pressure transient analysis technology has been applied to multiple injection projects. In general, the analysis results including formation and fracture properties (i.e. permeability, fracture half length, skin factor, and fracture closure pressure) are comparable to results from interactive analysis. Any discrepancies are mainly caused by poor data quality. Issues such as inconsistent selections of ISIP and different slopes defined for pre and after closure analyses also contribute to the divergence. Overall, the automated pressure transient analysis provides consistent results as the exact same criteria are applied to the pressure data, and analysis results are independent of the analyzer's experience and knowledge.As data from oil/gas industry increases exponentially over time, automated data transmission, storage, analysis and access are becoming necessary to maximize the value of the data and reduce operation cost. The automated pressure transient analysis presented here demonstrates that cloud storage and computing combined with automated analysis tools is a viable way to overcome big data challenges faced by oil/gas industry professionals.

Effect of different parameters on sealing performance of lost circulation process with dynamic fracture aperture testing apparatus

As one of the most common drilling problems, lost circulation causes severe economic losses. However, the commonly used experimental testing apparatuses and methods are inadequate to evaluate the dynamic sealing capacity of lost circulation process, which neglect the dynamic variation of fracture width. Thus, a lost circulation testing device containing dynamic fracture aperture was developed, which could be used to investigate the influence of lost circulation material (LCM) features, fracture geometry and fluid properties on sealing capacity by evaluating the maximum sealing pressure difference and equivalent plugging position. The wellbore pressure, fracture closure pressure and fracture tip pressure can be controlled and measured independently. The sensitive analysis results show that the sealing pressure has an opposite relationship with the equivalent radius of plugging zone. The particle blends selected by D50 Rule has the best sealing performance by bridging near the fracture mouth with the dynamic variation of fracture width. Properly narrowing the range of particle size distribution (PSD) increases the effective sealing concentration. The increase of LCM concentration improves the extensive adaptability of plugging zone with the same sized particles. The increase of LCM resiliency improves the adaptation of plugging zone to dynamic fracture width. The increase of fracture mouth aperture decreases the sealing capacity by extending the required plugging zone. The fluid viscosity increases the sealing capacity by increasing the carrying capacity of fluid and the flow resistance of lost circulation. The increase of injection rate decreases the plugging capacity by increasing the hydrodynamic disturbance.

Field experience and numerical investigations of minifrac tests with flowback in low-permeability formations

In this study, flowback-assisted minifrac tests were conducted in low-permeability shale and salt formations to measure the in situ stress. An injection/flowback testing protocol was implemented in each test to achieve accuracy and efficiency. Accurate and efficient injection/flowback testing is very important, given the impermeable nature of these formations and the need to complete each test as quickly as possible. Each flowback cycle yields a distinct and repeatable fracture closure signature, simplifying the interpretation of the fracture closure pressure. The objective of this paper is to share our field experience and to present a numerical analysis of the flowback test pressure responses, fracture closure behaviors, and fracture closure diagnostic methods. Examples from open-hole and cased-hole minifrac tests are used to demonstrate site operation procedures. Then, two numerical models are presented for simulating the fracture closure behavior during a flowback test. Field evidence is provided to demonstrate that the fracture closure pressures from the flowback tests are identical to those from tests without flowback. The fracture closure diagnostic methods for flowback tests are discussed, and it is found that the G-function diagnostic method yields a distinct fracture closure signal during the flowback tests. This study is intended to provide additional insights regarding flowback tests by sharing our successes, experience, and knowledge, thereby benefiting the industry.

Productivity Evaluation of Vertical Wells Incorporating Fracture Closure and Reservoir Pressure Drop in Fractured Reservoirs

In most oilfields, many wells produce in pseudo-steady-state period for a long time. Because of large reservoir pressure drop in this period, fractured reservoirs always show strong stress sensitivity and fracture closure is likely to occur near wellbores. The primary goal of this study is to evaluate productivity of vertical wells incorporating fracture closure and reservoir pressure drop. Firstly, a new composite model was developed to deal with stress sensitivity and fracture closure existed in fractured reservoirs. Secondly, considering reservoir saturation condition, new pseudo-steady productivity equations for vertical wells were derived by using the proposed composite system. Thirdly, related inflow performance characteristics and influence of some factors on them were also discussed in detail. Results show that fracture closure has a great effect on vertical well inflow performance and fracture closure radius is negatively correlated with well productivity. In this composite model, the effects of stress sensitivity of the inner and outer zone on well productivity are rather different. The inner zone’s stress sensitivity affects well productivity significantly, but the outer zone’s stress sensitivity just has a weak effect on the productivity. Strong stress sensitivity in the inner zone leads to low well productivity, and both inflow performance and productivity index curves bend closer to the bottom-hole pressure axis with stress sensitivity intensifying. Meanwhile, both maximum productivity and optimal bottom-hole pressure can be achieved from inflow performance curves. In addition, reservoir pressure is positively correlated with vertical well productivity. These new productivity equations and inflow performance curves can directly provide quantitative reference for optimizing production system in fractured reservoirs.

Research on support vector machine method for comprehensive evaluation after compression

Hydraulic fracturing is one of the important measures to increase production of oil and gas reservoirs. Pressure after the assessment of the existing technology is usually divided into direct and indirect diagnosis of hydraulic fracture. The diversity of evaluation results is due to the uncertainty and immaturity of the technology itself. Up to now, we have not found an economical and accurate hydraulic fracture evaluation method in the development and application of fracturing technology. In this paper, the pressure treatment technology after the comprehensive evaluation of boundary conditions is studied. By introducing the support vector regression theory, an evaluation model and a solution for correcting fracturing parameters are proposed. Fracturing parameters include fracture length, fracture height, fracture width, integrated fracturing fluid leakage coefficient, fracture conductivity, fracture closure pressure, and so on. For the optimization of various parameters, objective and scientific comprehensive evaluation results can be obtained by selecting different kernel functions. The results show that the model and method based on support vector machine are effective and practical.

Development of an Empirical Equation To Predict Hydraulic-Fracture Closure Pressure From the Instantaneous Shut-In Pressure Using Subsurface Solids-Injection Data

Summary During hydraulic-fracturing operations, conventional pressure-falloff analyses (G-function, square root of time, and other diagnostic plots) are the main methods for estimating fracture-closure pressure. However, there are situations when it is not practical to determine the fracture-closure pressure using these analyses. These conditions occur when closure time is long, such as in mini-fracture tests in very tight formations, or in slurry-waste-injection applications where the injected waste forms impermeable filter cake on the fracture faces that delays fracture closure because of slower liquid leakoff into the formation. In these situations, applying the conventional analyses could require several days of well shut-in to collect enough pressure-falloff data during which the fracture closure can be detected. The objective of the present study is to attempt to correlate the fracture-closure pressure to the early-time falloff data using the field-measured instantaneous shut-in pressure (ISIP) and the petrophysical/mechanical properties of the injection formation. A study of the injection-pressure history of many injection wells with multiple hydraulic fractures in a variety of rock lithologies shows a relationship between the fracture-closure pressure and the ISIP. An empirical equation is proposed in this study to calculate the fracture-closure pressure as a function of the ISIP and the injection-formation rock properties. Such rock properties include formation permeability, formation porosity, initial pore pressure, overburden stress, formation Poisson's ratio, and Young's modulus. The empirical equation was developed using data obtained from geomechanical models and the core analysis of a wide range of injection horizons with different lithology types of sandstone, carbonate, and tight sandstone. The empirical equation was validated using different case studies by comparing the measured fracture-closure-pressure values with those predicted by using the developed empirical equation. In all cases, the new method predicted the fracture-closure pressure with a relative error of less than 6%. The new empirical equation predicts the fracture-closure pressure using a single point of falloff-pressure data, the ISIP, without the need to conduct a conventional fracture-closure analysis. This allows the operator to avoid having to collect pressure data between shut-in and the time when the actual fracture closure occurs, which can take several days in highly damaged and/or very tight formations. Moreover, in operations with multiple-batch injection events into the same interval/perforations, as is often the case in cuttings/slurry-injection operations, the trends in closure-pressure evolution can be tracked even if the fracture is never allowed to close.

OPTIMISATION OF HYDRAULIC FRACTURING DESIGN IN LOWER OLIGOCENE RESERVOIR, KINH NGU TRANG OILFIELD

Kinh Ngu Trang oilfield is of the block 09-2/09 offshore Vietnam, which is located in the Cuu Long basin, the distance from that field to Port of Vung Tau is around 140 km and it is about 14 km from the north of Rang Dong oilfield of the block 15.2, and around 50 km from the east of White Tiger in the block 09.1. That block accounts for total area of 992 km2 with the average water depth of around 50 m to 70 m. The characteristic of Oligocene E reservoir is tight oil in sandstone, very complicated with complex structure. Therefore, the big challenges in this reservoir are the low permeability and the low porosity of around 0.2 md to less than 1 md and 1% to less than 13%, respectively, leading to very low fracture conductivity among the fractures. Through the Minifrac test for reservoir with reservoir depth from 3,501 mMD to 3,525 mMD, the total leak-off coefficient and fracture closure pressure were determined as 0.005 ft/min0.5 and 9,100 psi, respectively. To create new fracture dimensions, hydraulic fracturing stimulation has been used to stimulate this reservoir, including proppant selection and fluid selection, pump power requirement. In this article, the authors present optimisation of hydraulic fracturing design using unified fracture design, the results show that optimum fracture dimensions include fracture half-length, fracture width and fracture height of 216 m, 0.34 inches and 31 m, respectively when using proppant mass of 150,000 lbs of 20/40 ISP Carbolite Ceramic proppant.

A New Technique to Predict In Situ Stress Increment Due to Biowaste Slurry Injection Into a Sandstone Formation

Underground injection of slurry in cycles with shut-in periods allows fracture closure and pressure dissipation which in turn prevents pressure accumulation and injection pressure increase from batch to batch. However, in many cases, the accumulation of solids on the fracture faces slows down the leak off which can delay the fracture closure up to several days. The objective in this study is to develop a new predictive method to monitor the stress increment evolution when well shut-in time between injection batches is not sufficient to allow fracture closure. The new technique predicts the fracture closure pressure from the instantaneous shut-in pressure (ISIP) and the injection formation petrophysical/mechanical properties including porosity, permeability, overburden stress, formation pore pressure, Young's modulus, and Poisson's ratio. Actual injection pressure data from a biosolids injector have been used to validate the new predictive technique. During the early well life, the match between the predicted fracture closure pressure values and those obtained from the G-function analysis was excellent, with an absolute error of less than 1%. In later injection batches, the predicted stress increment profile shows a clear trend consistent with the mechanisms of slurry injection and stress shadow analysis. Furthermore, the work shows that the injection operational parameters such as injection flow rate, injected volume per batch, and the volumetric solids concentration have strong impact on the predicted maximum disposal capacity which is reached when the injection zone in situ stress equalizes the upper barrier stress.

Optimal Fracturing Parameters Condition of Integrated Model Development for Tight Oil Sands Reservoir with 2D Fracture Geometry Using Response Surface Methodology

In this study, oil production in tight oil reservoir was declined due to high heterogeneity, complicated and complexity of reservoir of the low permeability reservoir ranges from 0.1 md to 5 md and reservoir porosity ranges from 10 to 18% lead to low fracture conductivity among the fractures. The challenge deal with this problem is to stimulate the reservoir of hydraulic fracturing for maximum oil production is necessary for the study. The application of the central composite design and response surface are the best tool in order to optimize the operating parameters based on the maximum net present value and through the series calculation, the optimal operating parameters of hydraulic fracturing have been determined of 46 bpm of injection rate, 88.5 min of the injection time and 0.002 ft/min0.5 of the leak-off coefficient and the maximum net present value of 46.5 $mm. Finally, the integrated model development of hydraulic fracturing includes of the normal faulting stress regime, fracturing fluid selection and fluid model, proppant selection, fracture geometry, pressure model, material balance, fracture conductivity and simulation production of fractured well and unstimulated well that have been presented in this study. With the using two dimensional Perkins-Kern-Nordgren fracture geometry models coupled with carter leak-off as the 2D PKN-C has been used to account for leak-off coefficient, spurt loss in term of power law parameters to propagate the fracture half-length, fracture width. The result of the fracture conductivity of fractured well at the fracture half-length of 1,940 ft and average fracture width of 0.32 in by series calculated propped fracture concentration of 1.63 lb/ft2 and fracture closure pressure of 4,842.59 psi to fracture conductivity of 6,200 md-ft, which value is measured by the laboratory experiment. The post-fracture production has been shown the fold of increase oil of 18.7 and the oil production rate of fractured well demonstrated much rising compared to oil production rate of unstimulated case.

Numerical modeling of hydraulic fracture propagation, closure and reopening using XFEM with application to in‐situ stress estimation

SummaryIn this paper, a fully coupled model is developed for numerical modeling of hydraulic fracturing in partially saturated weak porous formations using the extended finite element method, which provides an effective means to simulate the coupled hydro‐mechanical processes occurring during hydraulic fracturing. The developed model is for short fractures where plane strain assumptions are valid. The propagation of the hydraulic fracture is governed by the cohesive crack model, which accounts for crack closure and reopening. The developed model allows for fluid flow within the open part of the crack and crack face contact resulting from fracture closure. To prevent the unphysical crack face interpenetration during the closing mode, the crack face contact or self‐contact condition is enforced using the penalty method. Along the open part of the crack, the leakage flux through the crack faces is obtained directly as a part of the solution without introducing any simplifying assumption. If the crack undergoes the closing mode, zero leakage flux condition is imposed along the contact zone. An application of the developed model is shown in numerical modeling of pump‐in/shut‐in test. It is illustrated that the developed model is able to capture the salient features bottomhole pressure/time records exhibit and can extract the confining stress perpendicular to the direction of the hydraulic fracture propagation from the fracture closure pressure. Copyright © 2016 John Wiley & Sons, Ltd.

Simulation of hydraulic fracturing with propane-based fluid using a fracture propagation model coupled with multiphase flow simulation in the Cooper Basin, South Australia

In many unconventional reservoirs, gas wells do not perform to their potential when water-based fracturing fluids are used for treatments. The sub-optimal fracture productivity can be attributed to many factors such as effective fracture length loss, low load fluid recovery, flowback time, and water availability. The development of unconventional reservoirs has, therefore, prompted the industry to reconsider waterless fracturing treatments as viable alternatives to water-based fracturing fluids. In this paper, a simulation approach was used by coupling a fracture propagation model with a multiphase flow model. The Toolachee Formation is a tight sand in the Cooper Basin, around 7,200 ft in depth, and has been targeted for gas production. In this study, a 3D hydraulic fracture propagation model was first developed to provide fracture dimensions and conductivity. Then, from an offset well injection fall off test, the model was tuned by using different calibration parameters such as fracture gradient and closure pressure to validate the model. Finally, fracture propagation model outputs were used as the inputs for multiphase flow reservoir simulation. A large number of cases were simulated based on different fraccing fluids and the concept of permeability jail to represent several water-induced damage effects. It was found that LPG was a successful treatment, especially in a reservoir where the authors suspected the presence of permeability jails. The authors also observed that total flowback recovery approached 76% within 60 days in the case of using gelled LPG. Modelling predictions also support the need for high-quality foam, and LPG can be expected to bring long-term productivity gains in normal tight gas relative permeability behaviour.

Evidence for a Highly Conductive Fracture after Water Fracturing in the GeneSys Project

AbstractThe GeneSys project aims to develop a low-permeability, sedimentary reservoir of the Northern German Basin for the provision of geothermal energy to heat the Federal Institute for Geosciences and Natural Resources (BGR) located at the Geo Center in Hanover, Germany. In May 2011, a massive fracturing (frac) operation was performed to create a large heat exchanger at a depth of 3,700 m. Subsequent to the frac operation, two low-rate injection tests were conducted below fracture-closure pressure. The injection phases of the two tests provide evidence for a large and highly conductive fracture, although proppants were not used during the frac operation, indicating that the fracture stays open because of self-propping effects, at least in the explored range of effective stress. Hydraulically active fracture areas of more than 0.5 km2 were calculated from an analysis of the pressure transient during the low-rate injection tests relying on matrix permeabilities determined in laboratory experiments. In pr...

Alternative methods to determine fracture closure pressure

Alternative methods to determine fracture closure pressure

Modelling Wellbore Transient Fluid Temperature and Pressure During Diagnostic Fracture-Injection Testing in Unconventional Reservoirs

Summary Diagnostic fracture-injection testing (DFIT) has gained widespread usage in the evaluation of unconventional reservoirs. DFIT entails injection of water above the formation-parting pressure, followed by a long-duration pressure-falloff test. This test is a pragmatic method of gaining critical reservoir information (e.g., the formation-parting pressure, fracture-closure pressure, and initial- reservoir pressure), leading to fracture-completion design and reservoir-engineering calculations. In typical field operations, pressure is measured at the wellhead, not at the bottom of the hole, because of cost considerations. The bottomhole pressure (BHP) is obtained by simply adding a constant hydrostatic head of the water column to the wellhead pressure (WHP) at each timestep. Questions arise whether this practice is sound because of significant changes in temperature that occur in the wellbore, leading to changes in density and compressibility throughout the fluid column. This paper explores this question and offers an analytical model for estimating the transient temperature at a given depth and timestep for computing the BHP. Furthermore, on the basis of the premise of a line-source well, we have shown that the early-time data can be represented by the square-root of time formulation, leading to the new modified Hall relation for the injection period.

DFIT 자료 해석을 통한 저류층의 투과도 및 초기압력 추정

Abstract Well testing in unconventional reservoirs, such as tight or shale gas formations, presents considerable challenges. It is difficult to estimate the reservoir properties in ultra-low permeability formation because of poor inflow prior to stimulation and excessive test duration. Moreover, radial flow may not develop in hydraulically fractured horizontal wells. For these reasons, the cost of test is high and the accuracy is relatively low. Accordingly, industry is turning to an alternate testing method, diagnostic fracture injection test (DFIT), which is conducted prior to the main hydraulic fracture treatments. Nowadays, DFIT are regarded as the most practical way to obtain good estimates of reservoir properties in unconventional reservoirs. Various methods may be used for interpreting DFIT data. This paper gives an explanation of those methods in detail and examines three actual field data. These show how various analysis methods can be applied to consistently interpret fracture closure pressure and time, as well as before and after closure flow regimes and reservoir properties from field data.

Establishing Key Reservoir Parameters with Diagnostic Fracture Injection Testing

Summary Diagnostic fracture injection testing (DFIT) is an invaluable tool for evaluating reservoir properties in unconventional formations. The test comprises injection of water over a short time, starting a fracture at the end of a well's horizontal section, followed by a long shut-in period. Analysis of the falloff data with the G-function plot reveals the fracture-closure pressure, and the fracture pseudolinear-flow period. In most tests, wellhead-pressure (WHP) measurements are used because of cost considerations. A wellbore-heat-transfer model is used to allow conversion of WHP to bottomhole pressure (BHP) by accounting for changing fluid density and compressibility along the wellbore. This model, in turn, allowed us to assess the quality of solutions generated with the WHP data. For DFIT analysis, we adapted the modified-Hall plot for the injection period, whereas both the pressure-derivative and G-function plots were used for the analysis of falloff data. The derivative signature of the modified-Hall plot allows unambiguous estimation of the fracture breakdown pressure (pf,) during the injection period. As expected, the pf, always turns out to be higher than the fracture-closure pressure (pfc), estimated with the two methods during pressure falloff, thereby instilling confidence in the solutions obtained. A statistical design of experiments with coupled geomechanical/fluid-flow simulation capabilities showed that the formation permeability is by far the most important variable controlling the fracture-closure time. Mechanical rock properties, such as Young's modulus of elasticity and the Poisson's ratio, play minor roles. In microdarcy formations, a longitudinal fracture takes much longer to close than a transverse fracture.

Characteristics of Productivity Curves in Abnormal High-Pressure Reservoirs

This article compares the permeability stress sensitivities of a matrix core, unpacked fractured core, and partly packed fractured core using an artificial core in experiments. Results indicate that the unpacked fractured core is much more sensitive to stress than the partly packed fractured core, and the matrix core has the worst stress sensitivity. In addition, a fracture closure model is established in order to analyze the well test data for abnormal pressure reservoirs, of which the productivity curve has a turning point on it. This new model assumes that the fracture will close near the well when the bottom-hole pressure reaches the fracture closure pressure. The closure radius expands as the closure pressure increases. The computational results show that the permeability deformation coefficient of the fracture zone has a greater impact on the productivity of the model than that of the fracture closure zone, and this model can fit the well test data very well.

Sawolo et al. (2009) the Lusi mud volcano controversy: Was it caused by drilling?

1. IntroductionThe Lusi mud volcano in Sidoarjo, East Java, was first noticed bylocal villagers at 5 am on the 29th May 2006. It started to erupt150 mfromtheBanjarPanji-1gasexplorationwell(Fig.1)twodaysafter the Yogyakarta Earthquake (5:54 am 27th May 2006), hasdisplaced 13,000 families and led to13 fatalities. The trigger for themud volcano has been the subject of significant debate (Davieset al., 2007, 2008; Manga, 2007; Mazzini et al., 2007; Tingayet al., 2008).The Sawolo et al. (2009) paper assesses and then dismisses thepossibility that there was a subsurface blowout (breakdown of thestructural integrity of the well) caused by a kick in the well (aninflux of water or gas from surrounding formations) whichoccurred on the 27th and 28th May 2006. For the subsurfaceblowout to have occurred, the pressure of the fluid (drilling mud,water, gas) in the unprotected section of the well has to exceed themaximum pressure the well can tolerate, which is estimated bya pressure test known as a leak-off test (LOT). To reach thisconclusion Sawolo et al. (2009) estimate what we deem to be anunrealistically high leak-off pressure (LOP) and unrealistically lowpressure within the borehole during the kick.Here we counter the main arguments made by Sawolo et al.(2009), pointing out inaccuracies, incorrect interpretations anddeviations from the daily drilling report (the factual account ofdaily operations). We also take this opportunity to describe for thefirst time direct evidence that the well was the cause of the mudvolcano. Lastly we show that their claim of an earthquake trigger isnot supported by the mud log data they present.2. What pressure could the well tolerate?The estimated LOP proposed by Sawolo et al. (2009) is 16.4 ppg(19.27 MPa/km) measured at 1091 m (1 ppg¼1.175 MPa/km). Indetermining the leak-off pressure (LOP), industryaccepted practiceis to take the inflexion point on a pressure build-up curve (Bell,1996; Enever et al., 1996; Addis et al., 1998; Jorgensen andFejerskov, 1998; Okland et al., 2002; Raaen et al., 2006; van Oortand Vargo, 2008). Based upon the pressure versus time plot(their figure 11), using this method the leak off was 15.8 ppg(18.57 MPa/km). The rationale stated by Sawolo et al. (2009) fornot interpreting the LOP by the conventional method is thatinterpreting leak-off pressure is less reliable when using oil-basedmuds and they suggest that the ‘fracture closure pressure’ shouldbe used instead.The fracture closure pressure (FCP) is generallyconsidered to beequaltotheminimum principalstressmagnitude andthus equaltothepressurerequiredtoopenanypre-existingfractures.Hence,theFCPcanbeanaccuratevaluetouseasformationstrength.However,the 16.4 ppg (19.27 MPa/km) value suggested by Sawolo et al.(2009) as the ‘fracture closure pressure’ is in contravention of alltechniques for estimating FCP. FCP is determined by carefullymonitoring the pressure decay in the well after the pumps areturned off (Enever et al., 1996; Jorgensen and Fejerskov, 1998;Raaen et al., 2006). The FCP can then be estimated from the pres-sure decay curve by a variety of methods, with the double tangentor root time methods most commonly used (Enever, 1993; Raaenet al., 2006). These techniques all require the pressure decay tobe monitored for a long duration after the pumps are shut-in(generally >10 min; Enever et al., 1996; Jorgensen and Fejerskov,

Determining Fracture Closure Pressure in Soft Formations Using Post-Closure Pulse Testing

Summary This paper discusses the theory and application of a pressure-pulse testing technique to determine the fracture closure pressure (Pc) in soft formations. This technique is intended for use only after a data fracture has been pumped and is closed. Implementing the pulse technique post-closure rather than while the fracture is still open allows it to be used as an independent determination of Pc without diminishing the accuracy of the fluid leakoff coefficient (CL) determined from the data-fracture. Previous pulse-testing techniques1 require pumping into a fracture while it is still open. This practice reduces the accuracy of CL by altering the time necessary for the fracture to close (tc). Furthermore, previous pulse-testing techniques yield only a possible range for Pc, whereas the post-closure pulse technique yields a better-defined, singular value of Pc. The accuracy of post-closure pulse testing is validated with several field examples from a soft formation on Alaska's North Slope by comparing a definitive Pc determined using pressure decline analysis with Pc determined from post-closure pulse testing.