Shut-in Pressure Research Articles

Inversion of creep parameters and their application in underground salt cavern energy storage systems for enhancing wind power integration

While the development of wind energy presents great potential and opportunities, the high level of uncertainty inherent in wind farms also poses considerable challenges for operators, especially when it comes to participating in the energy market. The intermittent and unpredictable fluctuation characteristics of wind power generation may cause significant deviations in the frequency and voltage of the grid, which pose a certain threat to the stability of the grid and power quality and need to be mitigated by advanced energy storage solutions. Salt caverns, these geological structures deep in underground space, are widely used in oil and gas storage, compressed air energy storage(CAES), and other projects around the world. In the operation of underground salt caverns as storage, there is no effective technical means to monitor the deformation of deep caverns in real-time. Therefore, developing a high-precision real-time prediction method for cavern volume deformation is of great significance for the safety assessment during the underground salt cavern operation. In this context, this paper proposes a comprehensive technical approach to meet the needs of real-time monitoring of the cavern status, including volume changes, in the intelligent construction of underground salt cavern facilities in China. Firstly, through the shut-in pressure test of the brine well, the volume shrinkage of the cavern during the monitoring period is obtained, and the creep parameters of the salt rock strata in the regional salt mine are inversely derived. Secondly, for a typical cavern in operation in this region, the creep deformation is predicted using numerical simulation methods. By analyzing the cavern volume deformation under different pressures, an empirical equation for cavern volume deformation is established. Finally, by combining the volume changes obtained from sonar tests conducted during the operation of the cavern, the accuracy of the simulated results and the theoretical model derived from the inverted creep parameters is verified. The real-time analysis method for cavern volume deformation developed from this research will be applied to the intelligent construction of underground salt cavern facilities, ensuring safe and controllable operation management of the storage facilities.

Coupling reservoir depletion and geomechanics to assess risks during post-blowout well capping: Case study on Macondo

Reservoir depletion can be consequential to wellbore integrity after a blowout, especially offshore. A prolonged post-blowout discharge extends reservoir depletion. “Underground blowouts” (tensile-fracture initiations) occurring after well capping, or shear-driven slow slippage of naturally-occurring pre-existing faults (PEFs) in the near-well vicinity, can compromise post-blowout wellbore integrity. Upward propagation of the initiated tensile fractures may trigger seafloor broaching by reservoir hydrocarbons.This study examines reservoir depletion analytically, evaluating associated geomechanical implications on the in-situ reservoir conditions and assessing the likelihood of tensile-fracture initiation (oriented longitudinally or transversely-to-the-wellbore) during post-blowout-well-capping operations, in addition to shear-driven slow slippage along PEFs in the near-well vicinity. A set of calculational procedures and thinking sequences are presented, necessary for encompassing the primary effects of post-blowout reservoir depletion on the in-situ stress state and the limits of tensile and shear failures that could aid in the appropriate blowout-contingency decision-making.Our novel, physics-based scheme (analytical-coupling approach) is applied to parameters from the MC 252–1 “Macondo Well” blowout from April 20, 2010 and the targeted M56 oil reservoir in deepwater Gulf of Mexico (GoM). The reservoir rock is modeled as a porous-permeable medium, considering fluid infiltration to-and-from the pressurized wellbore. The likelihood of an underground blowout correlates with the shut-in wellbore pressure buildup, after successful well capping.Elevated reservoir depletion via higher post-blowout-discharge flowrates and longer post-blowout-discharge periods (in terms of time duration) are shown to reduce the shut-in wellbore pressure buildup against time following well capping. The “critical discharge flowrate,” an established predictive indicator for underground blowouts following shut-in of an installed subsea-capping stack (SCS) is employed, using data from the post-blowout-discharge period, suggesting underground blowouts to be highly-unlikely for the set of parameters assessed. Finally, the Mohr-Coulomb criterion indicates that shear-driven slow slippage along PEFs in the near-well vicinity is also unlikely, considering the Macondo Well's bottomhole-wellbore-pressure history in the aftermath of the blowout.

Comparing different segments in shut-in pressure signals: new insights into frequency range and energy distribution

Water hammer diagnostics is an important fracturing diagnosis technique to evaluate fracture locations and other downhole events in fracturing. The evaluation results are obtained by analyzing shut-in water hammer pressure signal. The field-sampled water hammer signal is often disturbed by noise interference. Noise interference exists in various pumping stages during water hammer diagnostics, with significantly different frequency range and energy distribution. Clarifying the differences in frequency range and energy distribution between effective water hammer signals and noise is the basis of setting specific filtering parameters, including filtering frequency range and energy thresholds. Filtering specifically could separate the effective signal and noise, which is the key to ensuring the accuracy of water hammer diagnosis. As an emerging technique, there is a lack of research on the frequency range and energy distribution of effective signals in water hammer diagnostics. In this paper, the frequency range and energy distribution characteristics of field-sampled water hammer signals were clarified quantitatively and qualitatively for the first time by a newly proposed comprehensive water hammer segmentation-energy analysis method. The water hammer signals were preprocessed and divided into three segments, including pre-shut-in, water hammer oscillation, and leak-off segment. Then, the three segments were analyzed by energy analysis and correlation analysis. The results indicated that, one aspect, the frequency range of water hammer oscillation spans from 0 to 0.65 Hz, considered as effective water hammer signal. The pre-shut-in and leak-off segment ranges from 0 to 0.35 Hz and 0 to 0.2 Hz respectively. Meanwhile, odd harmonics were manifested in water hammer oscillation segment, with the harmonic frequencies ranging approximately from 0.07 to 0.75 Hz. Whereas integer harmonics were observed in pre-shut-in segment, ranging from 6 to 40 Hz. The other aspect, the energy distribution of water hammer signals was analyzed in different frequency ranges. In 0 − 1 Hz, an exponential decay was observed in all three segments. In 1 − 100 Hz, a periodical energy distribution was observed in pre-shut-in segment, an exponential decay was observed in water hammer oscillation, and an even energy distribution was observed in leak-off segment. In 100 − 500 Hz, an even energy distribution was observed in those three segments, yet the highest magnitude was noted in leak-off segment. In this study, the effective frequency range and energy distribution characteristics of the field-sampled water hammer signals in different segments were sufficiently elucidated quantitatively and qualitatively for the first time, laying the groundwork for optimizing the filtering parameters of the field filtering models and advancing the accuracy of identifying downhole event locations.

First Successful Wireline Stress Testing in a Gas Hydrate Reservoir in the Hyuganada Sea, Japan

This study presents a stress testing operation conducted using a wireline formation tester in a newly discovered gas hydrate prospect located offshore in Japan. The campaign, which spanned from December 2021 to January 2022, involved drilling a well using logging-while-drilling technology. Subsequently, wireline formation testing and stress testing were successfully conducted at three different depths within a gas hydrate-concentrated zone. The testing was accomplished in a single riserless descent, with the primary goal of obtaining crucial data such as mobility, formation pressure, and fracture gradient for one of the prospects. This operation marked the first stress testing job performed with dual packers in an open water and deepwater environment specifically for gas hydrate reservoirs. The study also provides a comprehensive interpretation of the data gathered during the operation. Moreover, it evaluates various properties such as formation mobility, formation pressure, initial breakdown pressure, closure pressure, fracture propagation pressure, and instantaneous shut-in pressure.

Investigation into hydraulic fracture propagation behavior during temporary plugging and diverting fracturing in deep coal seam

In this study, we conducted indoor temporary plugging and diverting fracturing (TPDF) experiments on samples of natural deep and shallow coal seams using a small-scale true triaxial fracturing simulation system. By integrating high-precision CT scanning technology and crack reconstruction techniques, and relying on the quantitative characterization of the crack complexity coefficient, we investigated the differences in internal structures between deep and shallow coal seam samples and the variations in the expansion of TPDF cracks. Furthermore, the study primarily focused on exploring the influence of temporary plugging agent (TPA) parameters (quantity and particle size) on the expansion patterns of TPDF cracks in deep coal seam coal-rock samples. The experimental results reveal that in shallow coal samples, artificially induced fractures are notably longer and extend to various surfaces of the samples. Conversely, in deep coal samples, the expansion of artificially induced fractures is influenced by well-developed cleavage and cleats. The crack complexity coefficient of artificial fractures in deep coal samples is 1.54 higher than that in shallow coal samples, with an increased crack width of 98 μm. However, the expansion distance of the fractures is shorter and does not extend to the S3 and S6 surfaces. Increasing the dosage of the TPA is advantageous for inducing frequent redirection of fractures and communication with previously untouched areas. When the dosage of the TPA is increased from 30 g/L to 60 g/L, the expansion distance of artificial fractures significantly increases, extending to various surfaces of the samples. The crack complexity coefficient increases by 1.1, and the crack width enlarges by 84 μm. Appropriate particle sizes of the TPA can effectively form seals. However, small particle sizes (200/400 mesh) struggle to seal initial fractures, while large particle sizes (10/20 mesh) can lead to excessive wellhead blockage, causing rapid shut-in pressure, destructive fracturing in deep coal samples, and the generation of a large amount of coal fines. This study holds significant guidance for the optimal selection of process parameters in the temporary plugging hydraulic fracturing of deep coal rock.

Well Shut-In Pressure Determination Method for Deepwater Drilling Considering Fluid-Solid-Heat Coupling

Blowout is one of the most serious safety threats in deepwater drilling. Considering the characteristics of gas invasion in complex formations, gas migration and distribution, and dynamic changes in temperature inside a wellbore, a deepwater well-closing pressure determination method considering thermal-fluid-solid coupling was proposed. The model was verified using actual data, and the average error in the increase in casing pressure during the closing process was found to be 5.42%. The shut-in pressure of oil and gas wells under a transient shut-in process was analyzed. The results showed that the fluid thermal expansion caused by temperature recovery had a significant impact on the change in wellhead backpressure after well closure. Furthermore, the time required for the wellbore pressure to recover to the formation pressure varies nonlinearly with factors such as geothermal gradients, pit gains, bottom-hole pressure, and gas production indices. A pressure calculation chart was developed for deepwater drilling. The shut-in time for deepwater drilling should not be less than 15 min, and in cases where the gas production index is small and the bottomhole pressure difference is large, the shut-in time should exceed 90 min. The results can provide theoretical guidance and technical support for well shut-in processes during deepwater drilling.

Influence of stress on the maximum shut-in pressure of double casing under non-uniform stress

When the natural gas well overflows, if the well cannot be shut in time, the pressure in the casing will increase and may lead to the risk of blowout. In this paper, the finite element analysis method is used to study the influence of the physical properties and geometric defects of cement ring in the double-layer casing combination model on the maximum shut-in pressure. It is found that the increase of the elastic modulus of the inner cement ring will increase the maximum shut-in pressure, and it is less affected by Poisson’s ratio. The lack of geometry will lead to the uneven circumferential equivalent stress of the inner casing, cause stress concentration, and reduce the internal pressure strength and the maximum shut-in pressure of the inner casing. Through the analysis of a natural gas well in Shuiyu area of Sichuan Basin, it is proved that the maximum shut-in pressure can be determined more accurately by analyzing the change of internal pressure strength of casing. After considering the supporting effect of double-layer casing, the calculation error is only 1.87%. This result has important guiding significance for the formulation of well control measures in the field.

Diagnostics of Secondary Fracture Properties Using Pressure Decline Data during the Post-Fracturing Soaking Process for Shale Gas Wells

In addition to main fractures, a large number of secondary fractures are formed after the volumetric fracturing of shale gas wells. The secondary fracture properties are so complex, that it is difficult to identify and diagnose by direct monitoring methods. In this study, a new approach to model and diagnose secondary fracture properties is presented. First, a new pressure decline model, which is composed of four interconnected domains, i.e., wellbore, main fractures, secondary fractures, and reservoir matrix pores, is built. Then, the fracturing fluid pumping and post-fracturing soaking processes are simulated. The simulated pressure derivatives reflect five fracture-dominated flow regimes, which correspond to multiple alternating positive and negative slopes of the pressure decline derivative. The results of sensitivity simulation show that the density, permeability, and width of secondary fractures are the main controlling factors affecting the size ratio. Finally, based on the simulated pressure decline characteristics, a diagnostic method for the identification and analysis of secondary fracture properties is formed. This method is then applied to three platform wells in the Changning shale gas field in China. This study builds the correlation between the secondary fracture properties and the shut-in pressure decline characteristics, and also provides a theoretical method for comprehensive post-fracturing evaluation of shale gas horizontal wells.

Full-cycle prediction of gas production variations in gas wells using different production methods

Gas production from gas wells is affected by formation pressure and wellbore outflow during gas production. To increase the daily gas production and obtain smooth and efficient gas production gas wells, methods such as wellbore shut-in pressure recovery and foam injection and drainage for gas production are usually adopted. In this paper, the gas-carrying liquid model, capacity prediction model, and pressure recovery model are utilized to establish a full-cycle production prediction method for newly developed gas wells. Combining the initial development pressure, gas production, and water production parameters of the gas well, the gas production prediction is obtained for the next few years. Meanwhile, the implementation time of the forced drainage method is calculated and obtained.

World’s largest natural gas leak from nord stream pipeline estimated at 478,000 tonnes

Methane is a potent heat trapping gas believed to account for 30% of the observed global warming to-date. At a capacity of 110 bcm/year, the Nord Stream (NS) pipeline corridor measuring 1,153mm in internal diameter and stretching 1,224km from Russia to Germany is the biggest in the world. The explosions that NS sustained in September, 2022, in the Baltic Sea, have unleashed the largest single methane gas source in recent memory. Over the course of 7days, our transient multiphase pipeline model has estimated that the gas leaks from 3 lines pumped 478,000 tonnes of methane into the atmosphere. A range of pipeline shut-in pressures as a function of leakage time deduced an envelope of gas volume that matched the timeline of observed outflows. Interestingly, the methane gas that escaped from the damaged threads amounted to the CO2 equivalent emitted by concrete sufficient to build about 27 Burj Khalifa towers.

Blowout-Capping-Fracturing-Relief Well: A Full Cycle Workflow

Summary Failed well-capping attempts following offshore-well blowouts undergoing worst case discharge (WCD) can lead to fluid-driven tensile failures (de facto hydraulic fracture initiations). Subsequent propagation of these fractures may lead to broaching of overburden-rock-formation layers and even the seafloor, providing pathways for reservoir hydrocarbons to escape into the seawater. After capping stack shut-in, the pressure buildup in the fluid column inside the wellbore exposes vulnerable locations to tensile (Mode I) failure. If this shut-in wellbore pressure exceeds the formation breakdown pressure (FBP) in any of the exposed-rock-formation layers, a fracture will initiate and will continue to propagate as long as sufficient energy is provided by the reservoir. Scenarios where the propagating fracture(s) broached the seafloor in the past led to severe environmental impacts, disturbing the local ecology. The quintessential example is Union Oil’s 1969 “A-21 Well” blowout in California’s Santa Barbara Channel, where subsequent well-capping attempts led to multiple broaching instances on the seafloor near the well with thousands of hydrocarbon gallons gushing into the seawater (observable from the sea surface as “oil boilups”). In this paper, numerical modeling is performed on a hypothetical case study using deepwater Gulf of Mexico parameters in order to evaluate the likelihood of a similar scenario by modeling a planar-fracture propagation longitudinally-to-the-wellbore, upon well capping. A workflow is developed that integrates post-blowout WCD flowrate and volume estimations, fracture initiation and propagation modeling following the capping stack shut-in, pertaining to a “cap-and-contain” strategy (including predictions in regard to seafloor broaching), along with relief-well intersection followed by kill-weight-mud injection. The casing-shoe depth is the presumed location of fracture initiation, assuming perfect integrity of all casedhole sections above it. Several sensitivity analyses are performed to investigate the impact of the casing-shoe depth, along with the stiffness of the overburden-rock-formation layer, and the post-blowout-discharge duration on the resultant fracture growth. Finally, the mud density and pump flowrate necessary to compensate the oil column to successfully kill the blown well are quantitatively assessed.

Pores collapse hysteresis damage evaluation in depletion-dependent oil reservoirs using an asymptotic-integro-differential perturbation method

This work proposes a new asymptotic-perturbative solution for transient pores collapse hysteresis modeling in depletion-dependent oil reservoirs with compaction effects during alternating loading/unloading cycles. The nonlinear hydraulic diffusivity equation (NHDE) is perturbed through a first-order expansion technique using the depletion-dependent permeability, k(p) as a perturbation parameter, ϵ. A new hysteretic deviation factor is presented for flow (drawdown) and well-shut (buildup) periods. This factor represents the permeability deviation during the drawdown and its partial restoration in the buildup period. The model calibration is performed by a porous media numerical oil flow simulator named IMEX®, and the results presented high accuracy for the drawdown and buildup of hysteretic and non-hysteretic cases (when the pores collapse did not occur yet). The practical uses of the model developed in this work are related to identifying flow regimes and hysteresis responses in pressure-sensitive reservoirs, estimating buildup pressure, and oil flow rates specification to prevent severe hysteretic behavior and history matching during reservoir surveillance. Two case studies related to different reservoir layers are researched, and for both cases, the results from the log–log plots analysis have shown that the infinite-acting-radial oil flow (1/2 value of the slope of the pseudo-pressure derivative) was identified. In addition, the log–log analysis also shows that the shut-in pressure has an influence on permeability loss. The main advantages of the solution derived in this work are the simple implementation, practical graphical analysis of the pores collapse hysteresis effect, the possibility of simulating different boundary conditions and well-reservoir settings, and the requirements of only a few pressure and permeability field data to input in the deviation factor. The solution proposed can be applied to choose the production time to shut the well and monitor the adequate oil flow rate during the production curve.

Estimation of the Fracturing Parameters and Reservoir Permeability Using Diagnostic Fracturing Injection Test

The term "tight reservoir" is commonly used to refer to reservoirs with low permeability. Tight oil reservoirs have caused worry owing to its considerable influence upon oil output throughout the petroleum sector. As a result of its low permeability, producing from tight reservoirs presents numerous challenges. Because of their low permeability, producing from tight reservoirs is faced with a variety of difficulties. The research aim is to performing hydraulic fracturing treatment in single vertical well in order to study the possibility of fracking in the Saady reservoir. Iraq's Halfaya oil field's Saady B reservoir is the most important tight reservoir. The diagnostic fracture injection test is determined for HF55using GOHFER software. Models for petrophysics and geology were calibrated using the diagnostic fracture injection test results after the petrophysical and geomechanical parameters of the rock have been determined. The HF55 vertical well, which penetrates the Saady reservoir, has well logs that have been used to evaluate the petrophysical and geomechanical parameters. These estimates have been supported by findings from the diagnostic fracture injection test through the utilization of standard equations and correlations. The findings of the diagnostic fracture injection test, often known as the diagnostic fracture injection test, are very compatible with the findings of the well logs. The diagnostic fracture injection test pre-falloff test event was examined to determine the instantaneous shut-in pressure and fracture gradient. In the meantime, Closure pressure, process zone stress, fracturing fluid efficiency, closure gradient, critical fissure opening pressure, storage correction factor, permeability, and pressure-dependent leak-off coefficient were all determined using the G function on plot. With the help of a specific software, the petrophysical and geomechanical properties of a single vertical well [HF55] was found. Saady B reservoir's upper and lower sections, along with it are therefore predicted to have the full range of petrophysical and geomechanical features. With the use of DFIT analysis, these features serve as the foundation for developing fracturing models.

Material Selection and Corrosion Rate Analyzed for CO2 Injection Well

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21818, “Material Selection and Corrosion-Rate Analysis for CO2 Injection Well: A Case Study of K1 Field CO2 Sequestration Project,” by Mohd A. Abu Bakar, Wan Amni Wan Mohamad, and M. Wahidullah M. Wahi, Petronas, et al. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ Typical materials used for CO2 injector wells are either corrosion-resistant alloys (CRA) or epoxy-lined tubulars. The most widely adopted CRA material is 25Cr, which features a high well-application cost. Application of materials other than 25Cr for CO2 injector wells are uncommon but may be fit for purpose. The complete paper describes material-selection methodology and corrosion studies performed in the K1 field CO2 sequestration project using materials other than 25Cr in an effort to optimize well costs and improve overall project economics without jeopardizing CO2 injector-well integrity. Introduction K1 field is in the Sarawak Basin at a water depth of 453 ft. It was discovered by an exploration well in 1972 and appraised by a dedicated well in 1992. The field features a gas column of 324 ft from the free water level at 4,990 ft true vertical depth subsea. Gas initially in place for this field is estimated at approximately 2,800 Bscf. CO2 storage screening studies had identified an opportunity to use the K1 field as a storage site. The source of CO2 gas is a nearby field, from which separated CO2 gas will be transported through a 130-km pipeline to the K1 field’s new injection-wellhead platform. The current plan is to inject and store the CO2 inside one of the depleted carbonate reservoirs until an increase in reservoir pressure to the initial pressure of 3,440 psi is observed. The reservoir temperature is approximately 120°C. Injection-Fluid Composition and Presence of Water Injection fluid contains a high mol% of CO2, methane, and other impurities such as nitrogen and hydrogen sulfide (H2S) gases. Injection fluid will be injected above the CO2 supercritical condition. Based on the injection fluid’s composition, CO2 will be the main source of corrosion in the presence of water when exposed to unprotected tubulars in the wells. The presence of H2S denotes the effect of stress corrosion cracking (SCC) and sulfide stress cracking (SSC), which must be considered in selecting tubing material for the injector wells. A small percentage of water (approximately 0.0086 mol%) also exists in the injection fluid. This will be detrimental to the injection wells in terms of corrosion if it is in the aqueous phase. To study this, the well’s shut-in and injection pressures and temperatures were plotted against the water-phase diagram. During these conditions, water in the injection fluid exists as vapor phase. Considering the possible risks of a higher percentage of water in the injection fluid, a more- conservative approach was taken in the selection of tubing material for the injector wells.

Integrated microseismic and geomechanical analysis of hydraulic fracturing induced fault reactivation: a case study in Sichuan Basin, Southwest China

Because of the special geographical location adjacent to the Tibetan Plateau, the geological setting of the Sichuan Basin is very complex, which brings a great challenge to shale gas development. In this study, we conducted an integrated microseismic and geomechanical analysis on a refracturing well in the Sichuan Basin. We observed that casing deformation occurred in the area of fault reactivation. However, the reactivation of pre-existing faults does not always cause casing deformation. In addition, a cluster of high-magnitude microseismic events will be triggered during the fault reactivation, which is also helpful to recognize the reactivated faults. Furthermore, according to the definition of b-value in the Gutenberg–Richter law, a group of high-magnitude microseismic events usually shows a low b-value and vice versa. Based on the analysis of treatment data and microseismicity, we found that there is a positive relationship between b-value and instantaneous shut-in pressure (ISIP): lower b-value represents lower ISIP. The investigation of the stress shadow effect based on the theoretical solution of a plane strain fracture is also convincing to prove the relationship between b-value and ISIP. Therefore, a significant relationship between hydraulic fracturing, microseismicity, and fault reactivation is established. Importantly, some useful implications of this relationship could be utilized for early warning of fault reactivation (probably casing deformation) and optimization of refracturing design for unconventional shale plays.

Technology Focus: History Matching and Forecasting (April 2023)

_ This year’s history matching and forecasting selections cover topics that include performance prediction of a polymerflood pilot in a heavy oil reservoir, multivariate characterization and modeling of a paleo zone, and multiwell pressure history matching in an unconventional reservoir. The authors of paper SPE 206247 developed a history-matched reservoir simulation model for a polymerflood pilot to enhance heavy oil recovery on the Alaska North Slope. According to the authors, the viscous fingering effect in the reservoir during waterflooding and the restoration of injection conformance during polymerflooding were effectively represented. Using the history-matched model, studies were conducted to investigate the oil-recovery performance under different development strategies, with consideration for sensitivity to polymer parameter uncertainties. In paper IPTC 22034, the authors present an approach that incorporates characterization of paleo zones, parameterization of paleo-zone conductivity, and application of flow profiles as a guide in the history-matching study of a conceptual reservoir simulation model under reservoir uncertainty. The authors conclude that the modeled paleo zone acts as a baffle inducing a partial confinement of the injectors. Solving a global optimization problem to minimize the mismatch between the instantaneous shut-in pressure and treatment pressures measured in the field and simulated by the model, for all stages and all wells, is the subject of paper SPE 204162. According to the authors, the technique reduces overfitting by minimizing the number of variables used for history matching, by increasing the number of wells and stages that are simultaneously matched, and by reproducing the dominant behavior of all stages instead of capturing the detailed behavior of specific stages. Recommended additional reading SPE 210224 Rate-Transient-Analysis-Assisted Numerical History Matching and Co-Optimization of CO2 Storage and Huff ’n’ Puff Performance for a Near-Critical Gas Condensate Shale Well by Hamidreza Hamdi, University of Calgary, et al. URTeC 3724391 Fractional Dimension Rate-Transient Analysis in Unconventional Wells: Application in Multiphase Analysis, History Matching, Forecasting, and Interference Evaluation by Behnam Zanganeh, Chevron, et al. SPE 200908 Application of an Integrated Ensemble-Based History-Matching Approach—An Offshore Field Case Study by Usman Aslam, Emerson, et al.

Pressure-Transient Analysis for Waterflooding with the Influence of Dynamic Induced Fracture in Tight Reservoir: Model and Case Studies

Summary It is well known that waterflooding will create fractures. The created fractures are divided into hydraulic fractures (artificial fractures with proppant) and induced fractures (formed during waterflooding without proppant). There is no proppant in the induced fracture, so it will close as the pressure decreases and extend as the pressure increases. We call it a dynamic induced fracture (DIF). Because of reduced pressure, the DIF will be closed during the shut-in pressure test (well testing). The current conventional well-testing model cannot describe the dynamic behavior of the DIF, resulting in obtaining unreasonable parameters. Thus, this work proposes a DIF model to characterize the DIF behavior during well testing (the injection well will shut in, resulting in a reduction in bottomhole pressure and induced-fracture closure). It is worth noting that a high-permeability zone (HPZ) will be formed by long-time waterflooding and particle transport. The HPZ radius will be greater than or equal to the DIF half-length because the waterflooding pressure can move particles but not necessarily expand the fracture. The point source function method and Duhamel principle are used to obtain the bottomhole pressure response. Numerical simulation methods are used to verify the accuracy of the model. Field cases are matched to demonstrate the practicability of the DIF model. Results show a straight line with a slope greater than the unit, a peak, a straight line with a slope less than one-half, and an upturned straight line on the pressure derivative curve. This peak can move up, down, left, and right to characterize the induced fracture’s dynamic conductivity (DC). The straight line with a slope greater than the unit can illustrate a fracture storage effect. The straight line with a slope less than one-half can describe the closed induced-fracture (CIF) half-length. The upturned straight line can describe the HPZ and reservoir permeability. The obtained parameters will be inaccurate if they are incorrectly identified as other flow regimes. Field cases are matched well to illustrate that identifying the three innovative flow regimes can improve the parameters’ accuracy. In conclusion, the proposed model can characterize the dynamic behavior of induced fracture, better match the field data, and obtain more reasonable reservoir parameters. Finally, two field cases in tight reservoir are discussed to prove its practicality.

Two New Methods for Defining Shut-In Pressure in Hydraulic Fracturing Tests

Hydraulic fracturing is one of the most common methods to determine in situ rock stress. The interpretation of the shut-in pressure to determine the minor principal stress is an important element of this method, and many different methods to interpret shut-in pressure have been studied and developed throughout the years. Each method has its advantages and disadvantages. With more than 50 years of research and development within the rock stress measurement field, especially in HF, SINTEF has established two practical ways of defining shut-in pressure. These methods are independent and termed zero flow and water hammer. The zero flow method has been used by SINTEF in more than 130 projects over the last 30 years. The methods clearly differ from the other methods as they are based on singular events in the development of pressure/flow versus time which enables us to read the shut-in pressure directly during testing. In this paper, a comparison is made between different methods for interpretation of shut-in pressure, including 12 existing methods and the 2 SINTEF methods. Comprehensive laboratory tests were performed, and a field test was selected from SINTEF’s database for demonstration and comparison of the methods. The SINTEF methods have been developed mainly for use in hard rock environment where the rock is a jointed aquifer and with low permeability. The application of the two methods has traditionally been hydroelectric power development, different types of tunnel, and cavern projects, and also in mineral mining. The methods have not been used in deep petroleum applications such as oil wells or offshore in porous rock types.

Location estimation of subsurface fluid-filled fractures: Cepstral predominant peak analysis and numerical study

In various subsurface resource development or fluid piping transportation problems, subsurface fluid-filled fractures often appear. Fracture location determination has always been critical in the related fields. Acoustic wave reflection at the junction and boundary in the pipeline can carry information about the property of the system. By using the accompanying acoustic wave information combined with the water hammer effect, the location of subsurface fractures can be estimated. A numerical fluid flow model for instantaneous shut-in is presented based on the water hammer effect. Fluid penetration effects, wellbore storage effect, and fluid inertial effect are considered. A method for determining the locations of subsurface fractures using cepstral predominant peak (CPP) is first proposed. By cepstral, we mean the inverse Fourier transform of the logarithm of the estimated signal spectrum. Also, the relationship between instantaneous shut-in pressure and cepstrum response is investigated in detail. To improve the robustness, CPP analysis based on Kaiser windowed cepstrum is used to identify the impulse period of fracture. Compared with the original cepstrum, Kaiser windowed cepstrum has the better performance for CPP analysis. The proposed flow model is impactful as it can provide pressure data with known fracture locations. Meanwhile, the data can be used to optimize and examine the performance of CPP analysis with Kaiser windowed cepstrum. A field experiment is conducted to validate the analysis about the acoustic wave in a pipeline system with fractures. By installing a high-frequency pressure monitoring device at the pump, the actual instantaneous shut-in pressure for an oil well is obtained. The experiment results show that the CPP analysis can obtain the fracture location efficiently and accurately, which can provide insights for engineering practices.

Machine-Learning and Physics-Based Models Compared in Downhole Pressure Prediction in Deepwater Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31758, “Downhole Pressure Prediction for Deepwater Gas Reservoirs Using Physics-Based and Machine-Learning Models,” by Jincong He, SPE, Matthew Avent, and Mathieu Muller, Chevron, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. Pressure measurements from permanent downhole gauges (PDHGs) during extended shut-ins often are used for model calibration and reserves estimation in deepwater gas reservoirs. A key challenge in practical operation has been the failure of PDHGs within the first few years of operation. To overcome this challenge, modeling solutions have been developed to enable accurate bottomhole well pressures to be calculated. In the complete paper, novel physics-based models and machine-learning (ML) models are presented and compared for estimating PDHG measurement from wellhead measurements. Introduction One way to predict PDHG shut-in pressure is with a full-physics wellbore simulator. However, those simulators usually require input parameters such as heat conductivity through the reservoir, itself highly uncertain in the field. In addition, wellbore simulation can be expensive computationally to run. The authors investigate two alternative modeling approaches to predict future PDHG shut-in data based on historical PDHG measurement from the same, or different, wells. The first approach is a physics-based data-driven (PBDD) method in which the temperature profile along the wellbore is characterized by a piecewise linear model, the cooldown process during shut-in is characterized by a decline-curve model, and the dependency of the cooldown on previous gas production is characterized by a linear model. During training, the parameters in these models are calibrated by historical PDHG shut-in data before gauge failure. Once trained, the model can be used to predict downhole measurement during future extended shut-in events. The second approach is to use ML methods. Using historical data, this approach trains a black-box model or function that directly projects the wellhead measurements and time since shut-in to downhole measurements. Both approaches are shown to be accurate when calibrated on historical data and used to predict future shut-ins of the same well. However, when they are used to predict shut-in pressure and temperatures of a new well based on other existing wells, the behavior of the ML model can be nonphysical and erratic, while the behavior of the PBDD model is more constrained and interpretable.