Step-rate Tests Research Articles

An interpretation of data after performing Step-rate-test in multi-layered, unconsolidated and weakly consolidated reservoirs

The prerequisite for this study is the difficulty in interpreting data after stimulation of the bottomhole formation zone has been carried out. The objectives of this work are the applicability and interpretation of Step-rate-test (SRT) data to evaluate suitable injection regimes in multilayered, unconsolidated and weakly consolidated reservoirs and the demonstration of the correlation between injection rate and pressure in a graphical format. We investigated the stability of the reservoir structure to pressure gradients by increasing pressure and injecting fluid through the injection well stock. We concluded that this stability does not improve over time. This means that the practical significance of this method lies in its ability to alter the pressure gradient when injecting fluid to maintain a constant flow rate. The constancy of the pressure gradient has a major impact on the stimulation of the bottomhole formation zone and therefore it can be concluded that the reservoir properties in the bottomhole formation zone are dynamic in nature and can change over time. It should be noted that the study found that a change in pore pressure within the loose rock can also affect the phase (effective) permeability, which in turn can affect the required pressure gradients during injection.

Best practices for characterization of High Temperature-Aquifer Thermal Energy Storage (HT-ATES) potential using well tests in Berlin (Germany) as an example

Application of Aquifer Thermal Energy Storage with High Temperatures (HT-ATES) ranging from 60–90 °C is a promising technique to store large amounts of energy in urban areas. However, these areas typically lack information on hydrogeological and thermal parameters of the subsurface to determine the potential for energy storage. Moreover, conventional exploration methods as pumping tests do not account for the variation in density caused by the high temperature gradients or changes in salinity as encountered in HT-ATES operation. The objective of this study is therefore to develop best practices for characterizing the hydrogeological and thermal properties of groundwater wells and their surrounding formation that determine the potential performance of HT-ATES-systems. In addition to conventional pumping tests, a set of Push–Pull tracer Tests (PPTs) with cold and hot water are proposed and scrutinized using Berlin as case study. There, the research well Gt BChb 1/2015, which is characterized by a reservoir temperature of 17 °C at a depth between 220 und 230 m below ground surface was tested.In 2017, seven Slug-Withdrawal Tests (SWTs), a Step-Rate-Test (SRT), a production tests, and two Push–Pull tracer Tests (PPTs) with hot and cold water were performed during a period of 40 days. These tests were accompanied by Distributed-Temperature-Sensing (DTS) monitoring. The temperature measurements provide indications of injection areas based on the warmback period during a PPT with 81 °C hot water.The determined aquifer transmissibility T=3.2×10−5m2/s, the related Productivity Index (PI=2.0m3/(h bar)), and maximum flow rates of about 5m3/h indicate that the aquifer has potential for HT-ATES. However, the PPT and the DTS monitoring revealed cross flow between the target aquifer and an overlying aquifer. Thus, a new well with a design avoiding cross flow is required to utilize the aquifer’s energy storage potential. A set of best practices for characterizing HT-ATES potential was derived from the experiences in this study.

New Mathematical Technique for Step Rate Test Analysis Aids Determination of Fracture Pressure and Overcomes the Uncertainty of Conventional Analysis.

Experience in the oil industry has shown that it is challenging to sustain successful long-term matrix injection, as injection water quality cannot be maintained rigorously due to facility hiccups and membrane clogging. Most oil field operators have resolved this problem of injectivity decline by increasing the surface injection pressure to part the formation and inject just above the fracture gradient with strict offtake management for zonal conformance. This is not an easy task as injection much above fracture opening pressure can lead to water fingering and poor sweep that results in uneconomical waterflood recovery. The operators, thus, strive to inject at a pressure just above the fracture opening pressure so that the fracture opens near the wellbore but does not extend and then maintain the pressure just above the fracture closing pressure. Therefore, determination of the fracture opening pressure and fracture closing pressure has remained critical data for the success of waterflood projects. The most reliable industry approach to estimating fracture opening and fracture closing pressures comes from the step rate test (SRT). This traditional approach of Cartesian analysis of pressure-rate plot fits straight lines through the data in a plot of injection pressure against injection rate and then estimates the fracture pressure from the intersection of these lines having different slopes. The data received often do not exhibit one clear change in slope, thus resulting in multiple possible solutions, making it difficult for the operator to use the data for high CAPEX facilities design. Most past studies indicate the subjectivity of this Cartesian slope fitting technique. Alternative solutions through multirate superposition analysis found limited application in the analysis of SRT data due to considerable sensitivity to the value of initial pressure used for superposition and lack of stability of rate and pressure data. In this article, a new technique of SRT analysis is presented, which provides a unique solution for fracture opening and fracture closing pressures. It helps to overcome the limitations of the traditional technique of arbitrary fitting of straight lines. It uses the mathematical understanding of cumulative derivatives to recognize that the matrix opens when the cumulative growth of the rate of injectivity shows a change. It estimates the derivative of the injection rate with respect to injection pressure at each step. Then, it estimates the fracture pressure from the plot of the cumulative of this derivative against pressure at each step. It helps to overcome the challenge SRT solutions posed by the nonlinear trend of pressure data at each injection step both before fracture and after fracture is initiated. It also overcomes the limitations of the multirate superposition technique, as it is not sensitive to the value of initial pressure used for superposition.

Two-dimensional models for waterflooding induced hydraulic fracture accounting for the poroelastic effects on a reservoir scale

This work focuses on the developing of a computationally efficient numerical model for a waterflooding induced planar hydraulic fracture in a poroelastic medium. In particular, under certain assumptions it is possible to decouple the fully coupled model into poroelastic reservoir and purely elastic fracture subproblems. Further, the general 3D problem formulation for a planar fracture is reduced to two dimensions for early time plane strain fracture and late time constant height fracture. Noticeably, the division of the problem into two subproblems allows us to use the displacement discontinuity approach for the fracture related part, and finite element method for the reservoir related part. The latter is especially important for the constant height fracture, which cannot be modeled using exclusively the finite element approach in two dimensions. The algorithm is benchmarked against the available analytical solutions, as well as compared to other numerical codes. The developed numerical method is used to study the influence of the heterogeneous pore pressure and the corresponding stress for different waterflooding fracturing situations. We consider the cases with both injection and production wells operating nearby. With the presence of such wells, the fracture growth becomes asymmetrical and both the well type and location are important. The qualitatively different fracture behavior is observed for various cases. Other numerical examples include the simulation of a step-rate test as well as investigation of the possibility of fracture control by altering the injection rate.

Unlocking the Potential of Acid Stimulation in Volcanic Rocks: A Successful Case with Integrated Analysis in Minami-Nagaoka Gas Field, Japan

Summary Acid stimulation of volcanic formations is rarely documented in the literature. A recent study however suggested its potential effectiveness through a comprehensive laboratory/modeling analysis and documented substantial permeability enhancement by dissolution of carbonate-cemented fractures in the near-wellbore area to create wormhole-like high-permeability channels. The study also presented a brief description of successful field execution, although operational details and analysis of results were not presented. This work presents in detail the field case of a multistage acidizing treatment in the Minami-Nagaoka gas field, a volcanic reservoir, and demonstrates the effectiveness of acid stimulation with 10% formic acid for productivity enhancement. The selection of a target well relies on the abundance of cemented fractures along a well. The operational design considers multiple field/well characteristics, such as low permeability; long, perforated intervals; and high-temperature conditions. Effectiveness of acid stimulation is evaluated comprehensively and justified by the integration of real-time stimulation diagnostics using distributed temperature sensing (DTS), real-time surveillance of bottomhole key parameters obtained thanks to coiled-tubing (CT) fiber-optic downhole telemetry, pre-/post-acidizing pressure buildup (PBU) tests, and production logging tool (PLT) surveys. A multistage acidizing operation was executed, after completion of a step-rate test during which a pre-acidizing DTS survey was acquired. Eight stages of 10% formic acid injection and seven stages of degradable particulate diverter placement were pumped, followed by brine displacement and a post-acidizing DTS acquisition. In all the stages, acid injection decreased the bottomhole pressure while the use of diverter increased it (by hundreds of psi), thus indicating success in acid stimulation and diversion, respectively. The stimulation almost doubled the gas flow rate just after the operation, and 10 months after the operation, the gas rate is still 1.5 times higher than before intervening. Pre-/post-acidizing PBU tests suggested a substantial reduction of the skin from 1.50 to −1.91. DTS surveying identified one major and three minor fluid-intake intervals through stimulation/diversion, and integrated analysis with PLTs revealed that the substantial improvement in gas rate was primarily coming from a narrow zone located within the major intake interval, where resistive fractures are abundant. The current case demonstrates the effectiveness of 10% formic acid for the stimulation of rocks with carbonate-cemented fractures, which was also proposed by the former study. It also shows that there is still room for further optimization in the operational design. This paper provides insights on acid stimulation in volcanic rocks and highlights its effectiveness through the analysis of a series of data sets. Readers may obtain knowledge on acidizing design, the evaluation of its effectiveness, and the interpretation of results, with lessons learned through job execution. The study will also serve as a reference to evaluate the potential of acid stimulation for the development of other volcanic reservoirs.

Simplified Hydraulic Jacking Test to Assess Fracture Normal Stress for Unlined Pressure Tunnels: A Field Experiment Using the Rapid Step-Rate Test

This paper describes an experimental campaign where a simplified test method. The Rapid Step-Rate Test (RSRT) has been investigated in a full-scale field setting. The test, originally developed to assess rock stresses for pressure tunnel considerations, had in an earlier laboratory study demonstrated a promising ability to assess the magnitude of fracture normal stress. The field campaign presented herein was therefore aimed at assessing the field applicability of this test. The field experiments were conducted inside the pressure tunnel of the Løkjelsvatn Hydroelectric Power Plant in Norway, under field conditions identical to those for which the test originally was developed. A total of 29 individual tests were conducted in 7 boreholes, providing 20 test cycles with interpretable test results. The stress estimates made from the test cycles not affected by the near-field stress of the tunnel showed good correlation with the magnitude of minimum principal stress found from a preceding hydraulic fracturing and over-coring stress measurement campaign. The experience from the field campaign suggests that the RSRT can represent an efficient and reliable method to assess the magnitude of minimum principal stress, particularly useful for the final design of unlined pressure tunnels.

New Empirical Correlations to Estimate the Least Principal Stresses Using Conventional Logging Data

The maximum (Shmax) and minimum (Shmin) horizontal stresses are essential parameters for the well planning and hydraulic fracturing design. These stresses can be accurately measured using field tests such as the leak-off test, step-rate test, and so forth, or approximated using physics-based equations. These equations require measuring some in situ geomechanical parameters such as the static Poisson ratio and static elastic modulus via experimental tests on retrieved core samples. However, such measurements are not usually accessible for all drilled wells. In addition, the recently proposed machine learning (ML) models are based on expensive and destructive tests. Therefore, this study aims at developing a new approach to predict the least principal stresses in a time- and cost-effective way. New models have been developed using ML approaches, that is, artificial neural network (ANN) and support vector machine (SVM), to predict Shmin and Shmax gradients (outputs) from well-log data (inputs). A wide-ranged set of actual field data were collected and extensively analyzed before being fed to the algorithms to train the models. The developed ANN-based models outperformed the SVM-based ones with a mean absolute average error (MAPE) not exceeding 0.30% between the actual and predicted output values. Besides, new equations have been developed to mimic the processing of the optimized networks. The new empirical equations were verified by another unseen data set, resulting in a remarkably matched actual stress-gradient values, confirmed by a prediction accuracy exceeding 90% in addition to an MAPE of 0.43%. The results’ statistics confirmed the robustness of the developed equations to predict the Shmin and Shmax gradients with a high degree of accuracy whenever the logging data are available.

Field Demonstration of the Impact of Fractures on Hydrolyzed Polyacrylamide Injectivity, Propagation, and Degradation

Summary During a polymer flood, the field operator must be convinced that the large chemical investment is not compromised during polymer injection. Furthermore, injectivity associated with the viscous polymer solutions must not be reduced to where fluid throughput in the reservoir and oil production rates become uneconomic. Fractures with limited length and proper orientation have been theoretically argued to dramatically increase polymer injectivity and eliminate polymer mechanical degradation. This paper confirms these predictions through a combination of calculations, laboratory measurements, and field observations (including step-rate tests, pressure transient analysis, and analysis of fluid samples flowed back from injection wells and produced from offset production wells) associated with the Kalamkas oil field in Western Kazakhstan. A novel method was developed to collect samples of fluids that were back-produced from injection wells using the natural energy of a reservoir at the wellhead. This method included a special procedure and surface-equipment scheme to protect samples from oxidative degradation. Rheological measurements of back-produced polymer solutions revealed no polymer mechanical degradation for conditions at the Kalamkas oil field. An injection well pressure falloff test and a step-rate test confirmed that polymer injection occurred above the formation parting pressure. The open fracture area was high enough to ensure low flow velocity for the polymer solution (and consequently, the mechanical stability of the polymer). Compared to other laboratory and field procedures, this new method is quick, simple, cheap, and reliable. Tests also confirmed that contact with the formation rapidly depleted dissolved oxygen from the fluids—thereby promoting polymer chemical stability.

Geomechanical properties will constrain CO2 injection into the lower Ordovician Rose Run sandstone deep saline reservoir, Appalachian Basin, Kentucky, USA

The Kentucky Geological Survey (KGS) 1 Hanson Aggregates stratigraphic research well, Carter County, Kentucky, USA, was drilled to a total depth of 1474 m as a field-scale test of potential CO 2 storage reservoir properties in the Central Appalachian Basin. Geomechanical properties of the Rose Run sandstone (upper Ordovician Knox group) were tested for its suitability as a storage reservoir. A 9.8-m thick section of the Rose Run was penetrated at 1000 m drilled depth and a whole-diameter core and rotary sidewall cores were taken. Average porosity and permeability measured in core plugs were 9.1% and 44.6 mD, respectively. Maximum vertical stress gradient calculated in the wellbore was 26 MPa/km. Wellbore fractures in dolomites underlying and overlying the Rose Run follow the contemporary N53°E Appalachian Basin stress field. The Rose Run elastic geomechanical properties were calibrated to values measured in core plugs to evaluate its fracturing risk as a CO 2 storage reservoir. Mean Young's modulus and Poisson's ratio values of the Rose Run were 45 GPa and 0.23, respectively, whereas Young's modulus and Poisson's ratio values were 77.1 GPa and 0.28, respectively, in the overlying Beekmantown dolomite, suggesting the Rose Run may fracture if overpressured during CO 2 injection but be confined by the Beekmantown. Triaxial compressive strength measured in core plugs found the Rose Run and Beekmantown fractured at mean axial stresses of 156.5 MPa and 282.2 MPa, respectively, confirming the Beekmantown as suitable for confining CO 2 injected into the Rose Run. A step-rate test was conducted in a mechanically-isolated 18.6-m interval bracketing the Rose Run. Static Rose Run reservoir pressure was 9.3 MPa, and fracture gradient under injection was 13.6 MPa/km, suggesting step-rate testing before CO 2 injection, and subsequent pressure monitoring to ensure confinement. As the region around the KGS 1 Hanson Aggregates well is underpressured and adjacent to faulted Precambrian basement, further research is needed to evaluate its induced seismicity risk during CO 2 injection.

Design for Reliability: Experimental and Numerical Simulation of Cased and Perforated Completions with Standalone Screen

Summary The historical challenges and high failure rate of using standalone screen in cased and perforated wellbores pushed several operators to consider cased-hole gravel packing or frac packing as the preferred completion. Despite the reliability of these options, they are more expensive than a standalone screen completion. In this paper, we employ a combined physical laboratory testing and computational fluid dynamics (CFD) for laboratory scale and field scale to assess the potential use of the standalone screen in completing the cased and perforated wells. The aim is to design a fit-to-purpose sand control method in cased and perforated wells and provide guidelines in perforation strategy and investigate screen and perforation characteristics. More specifically, the simultaneous effect of screen and perforation parameters, near wellbore conditions on pressure distribution and pressure drop are investigated in detail. A common mistake in completion operation is to separately focus on the design of the screen based on the reservoir sand print and design of the perforation. If sand control is deemed to be required, the perforation strategy and design must go hand in hand with sand control design. Several experiments and simulation models were designed to better understand the effect of perforation density, the fill-up of the annular gap between the casing and screen, perforation collapse, and formation and perforation damage on pressure drop. The experiments consisted of a series of step-rate tests to investigate the role of fluid rate on pressure drop and sand production. There is a critical rate at which the sand filling up the annular gap will fluidize. Both test results and CFD simulation scenarios are comparatively capable to establish the relation between wellbore pressure drop and perforation parameters and determine the optimized design. The results of this study highlight the workflow to optimize the standalone screen design for the application in cased and perforated completions. The proper design of standalone screen and perforation parameters allows maintaining cost-effective well productivity. Results of this work could be used for choosing the proper sand control and perforation strategy.

Rock Stress Measurements for Unlined Pressure Tunnels: A True Triaxial Laboratory Experiment to Investigate the Ability of a Simplified Hydraulic Jacking Test to Assess Fracture Normal Stress

To avoid hydraulic failure of unlined pressure tunnels, knowledge of minimum principal stress is needed. Such knowledge is only obtainable from in situ measurements, which are often time-consuming and relatively costly, effectively limiting the number of measurements typically performed. In an effort to enable more stress measurements, the authors propose a simplified and cost-effective stress measuring method; the Rapid Step-Rate Test (RSRT), which is based on existing hydraulic testing methods. To investigate the ability of this test to measure fracture normal stresses in field-like conditions, a true triaxial laboratory test rig has been developed. Hydraulic jacking experiments performed on four granite specimens, each containing a fracture, have been performed. Interpretation of pressure-, flow- and acoustic emission (AE) data has been used to interpret fracture behaviour and to assess fracture normal stresses. Our experimental data suggest that the proposed test method, to a satisfactory degree of reliability, can measure the magnitude of fracture normal stress. In addition, a clear correlation has been found between fracture closure and sudden increase in AE rate, suggesting that AE monitoring during testing can serve as a useful addition to the test. The rapid step-rate test is also considered relevant for field-scale measurements, with only minor adaptions. Our findings suggest that the RSRT can represent a way to get closer to the ideal of performing more testing along the entire length of pressure tunnel, and not only at key locations, which requires interpolation of stress data with varying degree of validity.

Application of the Modified Incremental Step Test for Pulmonary Rehabilitation.

A Modified Incremental Step Test (MIST) performed in the home may facilitate entirely home-based pulmonary rehabilitation programs. The aims of this study were to investigate the reliability and responsiveness, and the utility of the MIST for exercise prescription in people with stable chronic lung disease. The MIST was undertaken at the center and home in random order, before and after pulmonary rehabilitation, with 2 tests at each time point. Reliability was assessed using intraclass correlation coefficient. Responsiveness was evaluated as effect size. The minimal important difference was appraised using distribution and anchor-based methods. In a substudy, physiological responses to MIST were measured by a portable metabolic system, followed by a constant step rate test at 60% of peak oxygen uptake (VO2peak), to evaluate utility for exercise prescription. Forty-six participants were recruited (29% of eligible candidates). There was excellent reliability for number of steps recorded in home- and center-based settings (intraclass correlation coefficient = 0.954, 95% CI = 0.915-0.976). A small-moderate effect size was demonstrated following pulmonary rehabilitation (0.34), and the minimal detectable change was 7 steps. All participants in the substudy achieved 60% of VO2peak and achieved steady state by the fourth minute, with 60% of VO2peak corresponding to a mean 37% (95% CI = 29-44) of the MIST final level. The MIST is reliable and responsive to pulmonary rehabilitation in people with stable chronic respiratory disease. It provides new opportunities to assess exercise capacity, prescribe exercise training, and reassess exercise program outcomes in environments where established field walking tests are not feasible. Pulmonary rehabilitation is a highly effective treatment that is underutilized worldwide. Home-based pulmonary rehabilitation may improve access for patients and deliver equivalent clinical outcomes but is limited by the availability of a robust exercise test that can be used at home to assess exercise capacity and prescribe training intensity. This study tested the clinimetric properties of the MIST and demonstrated a new way to assess exercise capacity, prescribe exercise training of an appropriate intensity, and reassess exercise capacity in environments where established field walking tests are not feasible.

In-Situ Stress Measurements at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) Site

A scientific injection campaign was conducted at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) site in 2017 and 2019. The testing included pump-in/shut-in, pump-in/flowback, and step rate tests. Various methods have been employed to interpret the in-situ stress from the test dataset. This study focuses on methods to interpret the minimum in-situ stress from step rate, pump-in/extended shut-in tests data obtained during the stimulation of two zones in Well 58-32. This well was drilled in low-permeability granitoid. A temperature of 199 °C was recorded at the well’s total depth of 2297 m relative to the rotary Kelly bushing (RKB). The lower zone (Zone 1) consisted of 46 m of the openhole at the toe of the well. Fractures in the upper zone (Zone 2) were stimulated between 2123–2126 m measured depths (MD) behind the casing. The closure stress gradient variation depended on the depth and the injection chronology. The closure stress was found to increase with the pumping rate/volume. This stress variation could indicate that poroelastic effects (“back stress”) and the presence of adjacent natural fractures may play an important role in the interpretation of fracture closure stress. Further, progressively increasing local total stresses may, consequently, have practical applications when moderate volumes of fluid are injected in a naturally fractured or high-temperature reservoir. The alternative techniques that use pump-in/flowback tests and temperature signatures provide a valuable perspective view of the in-situ stress measurements.

Hydro-mechanical modeling of the first and second hydraulic stimulations in a fractured geothermal reservoir in Pohang, South Korea

This study presents comprehensive coupled hydro-mechanical numerical modeling of the first and second hydraulic stimulations at the Pohang enhanced geothermal system (EGS) site in order to improve the understanding on the key stimulation mechanisms in the fractured reservoir. Two models for PX-2 and PX-1 wells were developed including fracture zones of different orientations and permeability. Shear dilation and frictional plastic strain-softening were implemented in a non-linear stress dependent fracture model. A history matching of the wellhead pressure curves was carried out in the early days of each stimulation. The PX-2 model with a fracture jacking mechanism achieved the reproduction of highly reversible non-linear aperture changes observed in situ. The PX-1 model successfully simulated a wellhead pressure peak and drop associated with shear slip and dilation by applying frictional plastic strain softening. Simulated critical wellhead pressure for shear slip near the PX-1 well was greater than the prediction by a simple slip potential analysis due to local stress changes by the poroelastic effect. The numerical modeling confirmed that the combination of shear dilation and jacking was adequate to capture the pressure evolution during the increasing step-rate test at PX-1. Besides, spatio-temporal changes in pressure, total stress, and permeability evaluated in the fracture zones greatly enhanced the understanding on the coupled behavior caused by the hydraulic stimulations. The possibility of zones with lower permeability away from the PX-1 well was suggested by an alternative model. The current numerical study demonstrates that the key hydro-mechanical processes of shear slip and dilation and hydraulic jacking observed in the fractured reservoir can be successfully reproduced.

Multi-Basin Real-Time Perforation Assessment Using Tube Wave Measurements

This article addresses a means to improve hydraulic fracturing operations by measuring the perforation effectiveness on a stage-by-stage basis before the hydraulic fracturing process begins. Observations lead to the conclusion that pre-frac measurements provide meaningful insight about well-to-reservoir opening, allowing operators to identify the difficult-to-treat stages before the treatment begins. Based on the results of a case study from a North American unconventional basin, the limitations and conditions for employing pre-frac measurements are discussed. Background Often, perforation operations fail to initiate a well-established hydraulic communication between the wellbore and the reservoir rock. When hydraulic fracturing operations begin, a lack of wellbore to reservoir connectivity may cause unexpected difficulties such as unusually high pumping pressures, difficulty injecting the design volumes of fluid and proppant, and/or the inability to achieve design pumping rate or screenouts. The hydraulic fracturing industry is increasingly looking for an efficient, nonintrusive method for identifying poor wellbore to reservoir connectivity. Currently, step-rate tests are commonly used (Massaras et al. 2007) to give the operator an estimate of open perforations taking fluid, as well as frictional losses within the wellbore and near-field region. However, these tests are costly, time-consuming, and rarely accurately confirm the number of poor perforations (Cramer et al. 2019). Fiber-optic technologies can improve these uncertainties but are costly and susceptible to damage during installation and/or operation. How the Method Works Low-frequency hydraulic tube waves, or Stoneley waves (Stoneley 1924), are induced at the surface by equipment connected to the wellhead. Tube waves travel rapidly through the fluid within the wellbore and reflect by any changes within the hydraulically connected parts of the wellbore. In this case, the reflection off the bottom of the well influences the tube-wave properties - dispersion and attenuation of the normal modes (Hsu, Kostek, and Johnson 1997), depending on the condition and number of the perforations, the quality of their connection with the near-field region, and the quality of the near-field region itself (e.g., a region already naturally fractured) [Dunham et al. 2017].

Empirical Evidence Demonstrating Injection Containment and Absence of Injection-Induced Fracturing, Wilmington Oil Field Case Study

Summary Waterfloods in California operate under the US Environmental Protection Agency's Class II underground injection control regulations, which are tasked with the protection of underground sources of drinking water (USDW) within the state. A key aspect of this regulatory framework is the operation of water injection wells under a maximum allowable surface pressure (MASP) to ensure that injected water does not induce and/or extend formation fractures that could create a potential conduit connecting the hydrocarbon zone with identified USDWs. Determination of the MASP for individual injection wells has typically been calculated using a step rate test (SRT), but this method has been shown to be inappropriate for multilayered, unconsolidated sandstone reservoirs (Ershaghi and Ershaghi 2018), which are prevalent in Wilmington Field. To avoid the potential for misinterpretation of SRTs to imply fracturing in this context, in this paper we summarize the evidence demonstrating both the effective geologic containment of injected fluid in the hydrocarbon-bearing zones and the absence of injection-induced fracturing. In addition, a series of field tests were conducted to assess the stress sensitivity of the Wilmington reservoirs and investigate in-situ changes in the reservoir at higher injection pressures by combining multirate injection tests with injection profile surveys. These results provide data supporting the noted challenges associated with MASP determination for multilayered, unconsolidated reservoirs. In this paper, we give operators and regulators working in these types of fields a framework for assessing both injection containment and injection-induced fracturing that account for the unique properties of these formations.

High production improvement using channel fracturing in a tight conglomeratic sandstone reservoir

A novel method of hydraulic fracturing is by pulse pumping proppant into formation. The proppant is mixed with fibrous material, and this material will hold the formation from closing, even though channel if formed in the formation. A well producing from poorly sorting conglomeratic reservoir with secondary porosity and muddy micro-porosity. The well recently only produces intermittently 9 to 20 BOPD on sucker rod pump. Well permeability is 1.78 mD with reservoir pressure of 1188 Psi. The first step is to further evaluate the well, from rock mechanic and stress of formation, which is called Candidate Selective Factor (CSF). And then, a fracturing operation is designed, based on well parameter and surrounding wells. After performing pre-fracturing; consists of breakdown test, step rate test, and minifrac test; the operation is re-designed. The re-design includes special pulsing pumping technique, and the mainfrac operation. In the actual operation, the proppant was pulsing into formation for eleven times. The results of after channel fracturing shows that the productivity index increases 10.3 times. This new hydraulic fracturing method; Channel Fracturing; will also give less possibility of screen out, in addition to its successful result.

Effect of cold and hot water injection on the chemical and microbial composition of an aquifer and implication for its use as an aquifer thermal energy storage

A Triassic, siliciclastic aquifer was hydraulically tested for its suitability as aquifer thermal energy storage in the city of Berlin (Germany). This study investigates the effects of groundwater mixing, change of temperature, and water-rock interactions on the chemical and microbial water composition. The water chemistry was monitored during a step rate test and two subsequent tracer push pull tests (one conducted with aquifer water and the second with heated aquifer water). Apart of the main ions and physicochemical parameters, the microbial community were determined. In addition, molecular size distribution of dissolved organic carbon as well as the stable isotope compositions of strontium and water were measured in selected samples. This comprehensive monitoring resulted in the following main findings:The chemical water composition of all analysed samples was similar to seawater with main cations and anions correlating well with each other. Although the total element content varied over time, the produced water was homogenously mixed as evidenced by constant ratios of stable water isotopes. The most remarkable observation was an extremely high aluminium concentration (up to 4.7 mM) measured in the flowback after cold water injection. This can be explained by a hydraulic connection between the Triassic Formation and an overlaying Tertiary sand. Water-rock interactions between oxygen dissolved in the injected water and the pyrite-containing Tertiary sand eventually mobilized the aluminum.The measured effect of injecting hot water into the aquifer on the chemical and microbial composition was relatively small. However, temperature-dependent reactions might still be of relevance due to (I) the generally high microbial cell numbers that could trigger microbial enhanced reactions and (II) a calculated oversaturation of calcite that might result in mineral precipitation.

Characterization of laboratory-scale hydraulic fracturing for EGS

To investigate the impact of reservoir stimulation by hydraulic fracturing, a series of advanced lab-scale block tests were conducted with multiple measurement methods to characterize the fracture and to assess the operation and the performance of an enhanced or engineered geothermal system (EGS). The stimulation test samples were 330-mm cubic blocks of Sierra White granite with one injection well and four producers drilled into it. Acoustic emissions generated during the fracture initiation and propagation were monitored with twenty AE sensors mounted on all sides of the block to help characterize the fracture initiation and propagation process. The recorded AE signals were analyzed to obtain the event location and the failure mechanism. The localized AE events shows that due to the low viscosity of the fracturing fluid (water), the fracture propagated rapidly and took only about 1.4 s to reach near the block surface. During the fracturing phase, about 47 percent of the events were determined to be shear/mixed mode failure events, 28 percent tensile failure events, and 25 percent compressional failure events. Just after the simulation, a step-rate (constant flowrate) injection test was carried out to investigate the reservoir injectivity enhancement. During this phase additional compressional failure events were observed and the percentages of tensile failure and shear/mixed mode failure decreased. The dramatic increase of the injection rate with small increments of the injection pressure demonstrates the nonlinear response of the fracture to effective normal stress variation with much higher fracture opening increase during the low effective normal stress interval. Hydraulic fracturing tests under different stress levels show that more AE hits/events are recorded when the rock block is under higher applied stress. The reconstructed 3D fracture geometry shows good agreement with the AE monitoring results. After fracturing, a tracer test was carried out and the fracture aperture was estimated to be around 139 μm. The tracer recovery curve shows two linear portions of the tracer tail on a semi-log plot similar to that observed in some field data and predicted by numerical modeling. Laser scanning of the fracture surfaces indicates that the induced fracture has a rough surface with a joint roughness coefficient (JRC) of 12.98 and tortuosity of 1.10, both of which are slightly larger than that from the Brazilian test fracture on the same rock. The thin section and SEM observations show that the fracture follows the weak boundaries between the Quartz and Albite grains or the weak beddings in the grains.

Predicting the fracture initiation pressure for perforated water injection wells in fossil energy development

Water injection is widely performed to enhance oil recovery in fossil energy development. The fracture initiation pressure (FIP) is a key parameter for designing the reasonable injection pressure for micro-fracturing water injection (MFWI). In this work, a modified method was presented to accurately predict the FIP, in which the thermal effect and plugging effect were considered; moreover, the stress around perforations was analyzed. To validate our method, the field tests, including a step rate test (SRT) and a well test, were conducted to obtain the actual FIP for perforated water injection wells, and then the FIP calculated by our method was compared with a low relative error of about 1.7%. Results show that (i) a greater temperature difference between the injected water and the formation forms a greater thermal stress around perforations, resulting in a greater change in the FIP; (ii) a larger skin factor causes a greater pressure drop for the injected water flowing through a plugged area, resulting in a stronger effective stress reduction around perforations and further producing a larger FIP. Therefore, our present work illustrates a better understanding of the stress distribution around a perforated wellbore, and paves a path for a more accurate prediction of the FIP in perforated water injection wells.