Instantaneous Shut-in Pressure Research Articles

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.

Practical considerations for diagnostic fracture injection test (DFIT) analysis

The diagnostic fracture injection test (DFIT) provides a way to estimate parameters critical to hydraulic fracture design. Existing published models for before-closure and after-closure behaviors rely on assumptions, and failure to honor important realities leads to parameter estimation errors that could degrade hydraulic fracturing design. This paper is to illustrate an accurate way to estimate parameters from the DFIT data, and then discuss how these parameters should be used in the hydraulic fracture design, and at last offer an alternative DFIT design approach.Two fundamental concepts underlying the proposed methodology are the material balance before fracture closure and the diffusive flow in the formation after closure. Before closure analysis must correctly address abnormal leakoff behaviors and near well friction losses. Likewise, accurate permeability and pore pressure estimation requires correct accounting for the leakoff rate into the formation.Strict attention to material balance yields estimations for instantaneous shut-in pressure (ISIP) and perforation and tortuosity friction losses that may, in turn, avoid apparent very high net pressure and stress shadowing. This work also underscores the importance of understanding surface and downhole volumes and rates both in the DFIT design and in the analysis. Further, for the DFIT case with pressure dependent leakoff (PDL), the fracture design for the subsequent hydraulic fracturing treatment should use the apparent leakoff rate associated with the first closure trend instead of the leakoff rate associated with the last closure trend derived from a normal leakoff model. Two successive DFITs in the same perforation, the first treated with low injection rate and small volume and then the second with high rate and large volume, are proved to be a good practice to obtain reliable estimation of formation properties.This paper demonstrates that DFIT parameters have often been misused. With the proposed methodology, the interpretation will be more accurate and reliable for formation evaluation and hydraulic fracture design.

Lithology-controlled stress variations and pad-scale faults: A case study of hydraulic fracturing in the Woodford Shale, Oklahoma

We have conducted an integrated study to investigate the petrophysical and geomechanical factors controlling the effectiveness of hydraulic fracturing (HF) in four subparallel horizontal wells in the Mississippi Limestone-Woodford Shale (MSSP-WDFD) play in Oklahoma. In two MSSP wells, the minimum horizontal stress [Formula: see text] indicated by the instantaneous shut-in pressures of the HF stages are significantly less than the vertical stress [Formula: see text]. This, combined with observations of drilling-induced tensile fractures in the MSSP in a vertical well at the site, indicates that this formation is in a normal/strike-slip faulting stress regime, consistent with earthquake focal mechanisms and other stress indicators in the area. However, the [Formula: see text] values are systematically higher and vary significantly from stage to stage in two WDFD wells. The stages associated with the abnormally high [Formula: see text] values (close to [Formula: see text]) were associated with little to no proppant placement and a limited number of microseismic events. We used compositional logs to determine the content of compliant components (clay and kerogen). Due to small variations in the trajectories of the horizontal wells, they penetrated three thin, but compositionally distinct WDFD lithofacies. We found that [Formula: see text] along the WDFD horizontals increases when the stage occurred in a zone with high clay and kerogen content. These variations of [Formula: see text] can be explained by various degrees of viscous stress relaxation, which results in the increase in [Formula: see text] (less stress anisotropy), as the compliant component content increases. The distribution of microseismic events was also affected by normal and strike-slip faults cutting across the wells. The locations of these faults were consistent with unusual lineations of microseismic events and were confirmed by 3D seismic data. Thus, the overall effectiveness of HF stimulation in the WDFD wells at this site was strongly affected the abnormally high HF gradients in clay-rich lithofacies and the presence of preexisting, pad-scale faults.

Common Mistakes Associated With Diagnostic Fracture Injection Tests

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 169539, ’Diagnostic Fracture Injection Tests: Common Mistakes, Misfires, and Misdiagnoses,’ by R.D. Barree, SPE, J.L. Miskimins, SPE, and J.V. Gilbert, SPE, Barree & Associates, prepared for the 2014 SPE Western North American and Rocky Mountain Joint Regional Meeting, Denver, 16-18 April. The paper has not been peer reviewed. During the last 20 years, diagnostic fracture injection tests (DFITs) have evolved into commonly used techniques that can provide valuable information about reservoirs and hydraulic-fracture-treatment parameters. Thousands of tests are run every year in both conventional and unconventional reservoirs. However, many factors associated with data collection and analysis can result in poor or incorrect results. This paper attempts to describe some of the common problems and to help prevent some common errors often observed in DFIT execution and analysis. Introduction DFITs are small pump-in treatments performed to gather data to help design follow-up hydraulic-fracturing treatments and characterize a reservoir. A generic DFIT is shown in Fig. 1. The wellbore is first filled at a low to moderate rate until a positive surface pressure response is observed. With low- to- moderate wellbore compressibility, the pressure should rise quickly until initial breakdown occurs. Breakdown will be indicated either by a sharp drop in pressure as a new fracture initiates (as at Number 1 in Fig. 1) or by a plateau in pressure as existing fractures are opened and extended. Once a breakdown event is observed, the injection rate should be increased to the maximum rate allowed by available horsepower or to 75% of the planned treatment rate of the main fracture treatment, whichever is achievable. A constant rate is then held for 3–5 minutes (Number 2 in Fig. 1), after which a rapid step-down can be conducted. The step-down test is separate from the actual DFIT but is commonly run at the end of the pump-in to determine perforation and near-wellbore frictional pressure losses. The rate is then immediately reduced to zero to obtain the instantaneous shut-in pressure (ISIP), shown as Number 4, and the falloff pressure is monitored for as long as possible or as long as necessary to acquire the desired data. Even when high friction is not expected, the step-down is recommended to make identification of ISIP easier.

Leak-Off Coefficient Analysis in Stimulation Treatment Design

Hydraulic fracturing was first used in the late 1940s and has become a common technique to enhance the production of low-permeability formations.Hydraulic fracturing treatments were pumped into permeable formations with permeable fluids. This means that as the fracturing fluid was being pumped into the formation, a certain proportion of this fluid will being lost into formation as fluid leak-off. Therefore, leak-off coefficient is the most leading parameters of fracturing fluids. The accurate understanding of leak-off coefficient of fracturing fluid is an important guidance to hydraulic fracturing industry design. In this paper, a new field method of leak-off coefficient real time analysis model was presented based on instantaneous shut-in pressure (ISIP). More than 100 wells were fractured using this method in oil field. The results show that average liquid rates of post-fracturing was 22m3/d which double improvement compared with the past treatment wells. It had an important role for hydraulic fracturing stimulation treatment design in low permeability reservoirs and was proven that the new model for hydraulic fracturing treatment is greatly improved.

Field Method Research for Leak-off Coefficient Analysis Using Instantaneous Shut-in Pressure

Field Method Research for Leak-off Coefficient Analysis Using Instantaneous Shut-in Pressure

Defining Horizontal-Well Objectives in Unconventional and Tight Gas Reservoirs

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 137839, ’Defining Horizontal-Well Objectives in Tight and Unconventional Gas Reservoirs,’ by L.K. Britt, SPE, J.R. Jones, SPE, and W.K. Miller II, SPE, NSI Fracturing, prepared for the 2010 Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. The paper has not been peer reviewed. Because unconventional and tight-formation gas reservoirs have poorer-quality pay, a well-planned completion and fracture-stimulation program is required to obtain an economical well. Economic-optimization studies for tight gas reservoirs highlight the importance of lateral length, number of fractures, interfracture distance, fracture half-length, and fracture conductivity. A horizontal-well decision tree was developed for evaluating the various drilling, completion, and stimulation issues encountered with horizontal wells in unconventional and tight-formation gas reservoirs. Introduction Operators have reported difficulty in fracture stimulating some deviated and horizontal wells. The difficulties are associated with increased treating pressures and elevated post-fracture instantaneous shut-in pressures. In unconventional and tight-formation gas reservoirs, greater operational control and reliability are necessary to maintain project economics. Optimization studies of these reservoirs showed the importance and value of integrating horizontal drilling, completion, and well-stimulation practices. To understand the horizontal-well objectives in these reservoirs, a simulation study was undertaken, and the economics of multiple-fractured horizontal wells in tight gas reservoirs was investigated. Of interest in this evaluation were reservoir, completion, and stimulation parameters. Net pay, reservoir pressure, and reservoir permeability were evaluated. For the completion practices, completion control was considered; and for fracture stimulation, the effects of fracture length and conductivity were considered in light of fractured-horizontal-well objectives. Finally, horizontal-well drilling, completion, and fracture-stimulation costs were considered along with economic parameters to ensure that the horizontal-well objectives were established for all environments. Recoverable-Reserves Considerations The study compared reservoirs with 25, 50, and 100 ft of net pay. For a reservoir with limited net pay (25 ft), the optimal number of completions and fracture stimulations required to deplete the reservoir was five. Beyond five, there was little to no economic benefit from increasing the number of fractures. For a reservoir with 50 and 100 ft of net-pay thickness, the economically optimum number of completions was nine and 20, respectively. Thus, the greater the amount of recoverable gas, the more completions that are needed to recover those reserves optimally. Also, doubling the net pay in this example tripled the economic value, and quadrupling the net pay to 100 ft resulted in an eight-fold increase in the discounted net present value. Instantaneous potential (IP), or 30-day rate, for these three cases from 25 to 100 ft of net pay increased linearly with the number of fractures, up to 15 completions/fractures. However, beyond 15, the IP was not linear, indicating that the fractures were interfering with each other within 30 days.

An Overview of Horizontal-Well Completions in the Haynesville Shale

Summary A steep learning curve has evolved in drilling and completing horizontal wells in the Haynesville shale. The challenge is to understand the production mechanism of the Haynesville and how completion practices in relation to lateral lengths, stages, and stimulation treatments relate with production. This paper gives an overview of the Haynesville horizontal-well production and the dominant factors that affect production, along with a detailed analysis of the completions. Dominant factors that affect production in the Haynesville shale can be divided into four categories: geology/petrophysics/geomechanics, landing and placement of the lateral, completions, and production control. Integrating all four categories is critical to characterize well performance and optimize future production; however, this paper focusses primarily on the completions. Self-organizing maps (SOMs) of 49 wells in the strait region of the Haynesville shale reveal that high-producing wells have been treated primarily with slickwater, high fluid and proppant volumes, moderate amounts of 100-US-mesh sand, and moderate pump rates per perforation. These wells are typically located in cluster spacing of approximately 75 ft and have stage lengths of approximately 300 ft. Most show lower post-fracture instantaneous shut-in pressure (ISIP) than lower-producing wells. These observations and characteristics of high-producing wells along with best completion practices can help design optimal completions and stimulation treatments in the Haynesville.

Hydromechanical analyses of the hydraulic stimulation of borehole Basel 1

We analysed the response of the underground penetrated by borehole Basel 1 to two pumping sequences, a pre-stimulation test (flow rate up to 10 L min−1) followed by a step-up stimulation (starting from 10 L min−1 up to 3380 L min−1), performed to generate a heat exchanger at about 5 km depth. Throughout the test sequences an increase in flow rate resulted in an increase in injection pressure. Yet, sudden pressure drops (≲0.1 MPa) as well as a continuous decrease in pressure occurred at constant flow rates above 100 L min−1. Analysis of the pre-stimulation record strongly suggests the existence of a vertical fracture prior to stimulation. We focused on two contrasting scenarios in fracture height and normalized fracture conductivity out of the range of possible geometrical characteristics of this pre-existent fracture as constrained by numerical modelling. Independent of chosen scenario, the initially modest pressure increase can only be modelled by hydraulic properties that change with fluid-pressure. The spatio-temporal characteristics of the pressure distributions differ significantly for the two scenarios; the ‘formation linear flow’-like pattern found for the scenario with the larger fracture height of 100 m matches geometrically better with the oblate seismic cloud than the ‘radial flow’-like pattern found for the smaller fracture height of 10 m. It is problematic to explain the drops in pressure observed at constant flow rate by lateral or vertical extension of the pre-existent vertical fracture in classical tensile hydrofracturing mode considering the persistent increase in pressure with every step-up in flow rate throughout the entire stimulation and the lack of reproducible and distinct instantaneous shut-in pressures. We suggest shearing and wing-extension of the pre-existent fracture(s) as an alternative mechanism since this mechanism (a) is consistent with the absence of a distinct breakdown in pressure, (b) can be initiated at fluid pressures below the least principal stress and (c) can explain the pronounced change in hydraulic properties with increasing injection pressure as well as the observed rapid small pressure drops at constant flow rate.

Adverse effects of pore-pressure drainage on stress measurements performed in deep tunnels: an example from the Lower Kihansi hydroelectric power project, Tanzania

We describe a campaign to measure stress within a gneissic ridge near the edge of the Tanzanian craton . The measurements were conducted to determine whether the level of minimum principal stress along the trajectory of a hydropower pressure tunnel attained the level of 10 MPa, as required to leave the tunnel unlined. Extrapolation of early hydrofracture and overcoring measurements conducted mostly in boreholes drilled behind face suggested that the requisite level was not quite met. However, the minimum principal stress estimates from the instantaneous shut-in pressures (ISIPs) of the hydrofracture tests generally showed large scatter and were sometimes less than the estimated pre-disturbance pore pressure . It was suspected that the stress tests were affected by stress alteration around the tunnel due to pore pressure drainage. To test this, hydrofracture and hydro-jacking tests were conducted in two long, horizontal holes drilled ahead of the excavation face into relatively undrained rock, and a third vertical hole drilled behind the face. All were near the critical location where the pressure tunnel enters the powerhouse. The minimum principal stress estimates in the ahead-of-face holes were found to be much higher than those from the behind-face hole, consistent with the hypothesis. Estimates of the drawdown in pore pressure about the tunnel and test holes suggested a coupling factor between drawdown and minimum principal stress magnitude of approximately unity. This is slightly higher than predicted from an hydromechanical model that explains the coupling between the pore-pressure and stress fields in terms of fracture compliance and poro-elasticity of intact blocks. Nonetheless, both results demonstrate the importance of accounting for drawdown when conducting stress measurements in boreholes drilled from tunnels. We also note some instances where hydrofracture and hydro-jacking tests yielded different estimates for the minimum principal stress magnitude.

The use of leak-off tests as means of predicting minimum in-situ stress

Leak-off tests (LOTs) or, preferably, extended leak-off tests (XLOTs), can be successfully used in minimum in-situ stress, S 3 , estimations. Selecting a point on the leak-off graph that represents the best proxy for S 3 can reduce inaccuracies in the use of LOTs as a means of determining S 3 . If the testing procedure is well conducted and recorded, picking the leak-off pressure (LOP) or instantaneous shut-in pressure (ISIP) gives equally valid estimates of S 3 . During testing, most of the pressure applied in the deduction of S 3 is exerted by the static mud column, particularly in overpressured settings where higher drilling mud weights are used. Since the mud column contributes such a large proportion of the applied pressure, estimating S 3 from tests conducted at greater depth means the observed small difference between LOP and ISIP has even less of an effect on the deduced S 3 value. The data used in this study show that LOP closely matches ISIP when considering multiple cycle XLOTs. It can therefore be inferred that the LOP is the fracture re-opening pressure and hence S h given that the assumptions made by the Kirsch equation for wellbore failure are upheld. This study also considers the implications for calculating the magnitude of S H .

Measured and Calculated Horizontal Stresses in the Travis Peak Formation

Summary This paper presents the results of an experimental program to determine in-situ horizontal stress magnitudes from the dynamic mechanical properties of tight-gas sand cores. These measurements were made on 47 vertical plug samples from the Gas Research Inst. (GRI) test wells, Staged Field Experiment (SFE) Wells 1 through 3. The wells were cored in the Travis Peak formation of east Texas from ≈ 6,500 to ≈ 9,500 ft deep. Vertical overburden stress gradient was measured in one well using a downhole gravimeter. The core mechanical properties were used with the Anderson and Newberry equations to calculate in-situ horizontal stress. Actual in-situ minimum horizontal stress was determined from instantaneous shut-in pressures measured during minifracture and microfracture tests. The Newberry equation was found to give results that agreed best with measured horizontal stress. A closer match was obtained between measured and calculated horizontal stress values when we used dynamic Poisson's ratio from partially gas-saturated samples. The assumptions and limitations of the procedure are presented.

Evolution of the plastic zone near a microfracture: a numerical Simulation and its implications on in situ stress measurement

The instantaneous shut-in pressure has been used to estimate the far-field in situ minimum principal stress during microfracture testing. A plastic zone can be induced near the fracture. Because of the early plastic (irreversible) deformation induced near the fracture, the irreversible deformation near the fracture surface reduces the fracture pressure and generates a discrepancy between the far-field minimum stress and the fracture closure pressure, which has been identified as the minimum in situ stress in the past. In this paper, a finite-element numerical model is used to investigate this discrepancy due to the plastic deformation near a fracture. It is concluded that a plastic zone can be generated near a hydraulic fracture in poorly consolidated media. The fracture closure pressure can be much smaller than the minimum in situ stress due to the irreversible deformation generated near the fracture during the active fracturing period. Thus, one cannot use the conventional hydraulic-fracturing technique to interpret the minifracture tests in a poorly consolidated medium such as oil sand. Key words : microfracturing, in situ stress measurements, oil sands, plasticity, numerical simulation.

New Insights Into Fracturing Pressure Interpretation: Case Study Of Minifracture Tests In A Naturally Fractured Gas Reservoir

Abstract This paper presents a detailed analysis of three minifracs and an acid fracture treatment in a well completed in the Devonian Wabamun Formation near the boundary separating Shell Canada's Limestone and Burnt Timber gas fields in western Alberta. The purpose of this well test program was to gather data for the design of a large acid fracture treatment, if it could be shown to be economically feasible. The minifracs were pumped consecutively and were composed of plain water and combinations of gelled water, diesel. Silica flour and 100 mesh sand. Calculated bottomhole pressures are plotted against various time functions to determine the instantaneous shut-in pressure (ISIP), fracture closure pressure (FCP) and the leakoff behavior of various fluid systems. The importance of using FCP selection techniques based on the nature of the flow regime is demonstrated. The recently proposed fracture model of Shlyapobersky et al. is used to determine the total leakoff coefficients by a global least squares matching technique. Leakoff behavior is shown to be dependent on several factors including the choice of fluid additives, the fracture closure pressure or minimum in-situ stress, the presence of natural fractures and possibly the intermediate and major principal in-situ stresses. Anomalously high propagation pressures were observed during one of the minifracs. These high pressures are believed to have caused either natural fractures or secondary induced fractures to open, resulting in nearly an order of magnitude greater leakoff coefficient than was calculated for lower bottomhole pressures in an earlier test in the same well. Introduction The successful stimulation of wells completed in deep, low permeability, dolomite formations in the Canadian Foothills requires a consideration of fracture geometry and fracturing fluid leakoff behavior. In order to achieve long penetrating fractures with either acid-based or proppant-laden fluids an efficient but non-damaging fluid system is normally desired. The most common procedure for assessing the leakoff behavior, fracture geometry and fracture closure pressure present within a candidate fracture zone is to conduct a minifracture test using the actual pad fluid system proposed for the main treatment. Shell Canada's experience in stimulating such reservoirs has been recently described in papers by Milligan et al.(1,2). Minifrac test procedures and interpretation has been the subject of considerable investigation and controversy over the last 10 years(2–12). Despite the extensive work on the topic and at least two international workshops on in-situ stress measurement many uncertainties often remain in the interpretation of hydraulic fracture injection tests. Several factors have been shown to influence the post shut-in, pressure decline behavior of vertical fractures including: fluid injection rate, fluid rheology, permeability, fluid leakoff additives, temperature, fluid compressibility, fluid pressure, minimum horizontal in-situ stress, and the opening of natural fractures. Interpretation techniques have improved considerably and there are now models available which address and correct for many of these effects which may obscure or distort the true fracture closure pressure and the total leakoff coefficient(11–13). This paper presents a case history describing a series of minifracs followed by an acid fracture treatment on a shut-in gas well located near the boundary of Shell Canada's Limestone and Burnt Timber gas fields of western Alberta (Fig. 1).

Fracture closure pressures from free-oscillation measurements during stress testing in complex reservoirs

A novel yet simple technique will be described that permits an accurate field determination of fracture closure pressure to be acquired during the course of normal in situ stress or minifrac testing. The basis of this promising new technique involves the observation of an induced wellbore pressure pulse that is subsequently altered through its dynamic interaction with a compliant hydraulic fracture. The careful observation and measurement of these pulses or free wellbore oscillations will provide suitable data from which to determine the pressure at which the fracture finally closes. Wellbore pressure impulses are extremely sensitive to the fracture and fracture fluid dynamics and if correctly measured, provide considerable insight into fracture and formation characteristics. If, however, pressure measurements are acquired at a rate too slow to capture and describe these oscillations (which occur at the fundamental resonant frequency of the well and the first several higher-order harmonics), aliasing of the data will result. Aliasing can lead to erroneous selecting of the instantaneous shut-in pressures (ISIP), falloff and fracture closure pressures.

Interpretation of hydraulic fracturing pressure-time records using interactive analysis methods

The accuracy of hydraulic fracturing stress measurements depends strongly on an accurate interpretation of the fluid pressures recorded during the tests. However, a variety of factors can lead to indistinct instantaneous shut-in or fracture reopening pressures which contributes to uncertainties in the data interpretation. A complex hydrofrac data set from a 1.5 km deep wellbore at Moodus, Connecticut is used here to discuss an interactive system for analysis of pressure, injection rate and accumulated volume as well as the pressurization rate and stiffness of the hydraulic system at various stages of the experiment. The hydraulic fracturing data presented here require a particularly careful inspection of the pressure records because the tests at Moodus were conducted in a seismically active reverse faulting environment. In such a stress regime (when the least principal stress is vertical) induced vertical fractures at the borehole wall will tend to “roll over” and propagate horizontally. Ideally the complete stress tensor can be derived from such a test but it is necessary to clearly separate the shut-in pressure values of the different propagation stages.

Interpretation of hydraulic fracturing shut-in curves for tectonic stress measurements

The closure process after shut-in of the cracks which are induced by hyraulic fracturing on the surface of a wellbore is analyzed to discuss the physical meaning of shut-in curves. The analysis is based on the linear theory of elasticity and also on linear fracture mechanics. It is shown that the pressure decay characteristics of shut-in curves are primarily governed by the leak-off rate, the equipment compliance and the partial crack closure. It is also shown that the downhole fluid pressure at the onset of the closure of the crack tip is very close to the compressive tectonic stress normal to the crack plane. This pressure can be detected as the point of maximum curvature on each shut-in curve. Finally, the methods which have been proposed so far for the determination of instantaneous shut-in pressures are also applied and their applicability and reliability are discussed.

In Situ Stress Magnitudes From Mini-Frac Records In Western Canada

Abstract This paper lists instantaneous shut-in pressure and closure stresses derived from the records of 115 mini-frac tests run in western Canada in recent years. One hundred and eight of the mini-froes were run in Alberta wells and this data set is reviewed briefly. The measurements were made largely in reservoir sandstones, some of which exhibited formation pressures that had been lowered by recent production of hydrocarbons. There is considerable variability in the measured magnitudes of the smaller horizontal principal stress, SHmin both locally and regionally, although the average gradient is similar to that of the Gulf Coast. Many SHmin magnitudes are low enough to suggest that SV>SHmax>SHmin over much of the Alberta Plains. Higher SHmin values were obtained from wells within or near the foothills, painting to a regime where SHmax>SV>SHmin but these mini-fracs were largely from deeper tests than those run beneath the plains. Hence, it is not proven whether SHmin actually increases toward the mountains or whether there is only a change in gradient with depth. Introduction In recent years it has become clear that many practices in hydrocarbon exploration and production would benefit from an increased understanding of subsurface in situ stresses. It has long been recognized that principal stress orientation controls the propagation direction of hydraulic fractures(1). More recently, the effects of variations in horizontal principal stress magnitudes have been shown to affect fracture containment(2, 3) and borehole stability(4). The state of stress at a point within the earth can be completely described by three mutually perpendicular principal stresses. These stresses are assumed to be oriented vertically and horizontally(1, 5). Each can be considered as the sum of the effective stress component and pore pressure, so that:Vertical stress: S V = σ V + P oMaximum horizontal stress: S Hmax = σHmax + P o(1)Minimum horizontal stress: SHmin=σHmin+P0 where S = total stress σ= effective stress Po = formation fluid pore pressure Hydraulic fractures propagate perpendicular to the least principal stress. Although horizontal hydraulic fractures have been documented in the subsurface(6), the majority of hydraulic fractures are vertical, indicating that the least principal stress is usually horizontal(1). Therefore, earth stress measurements obtained directly from hydraulic fracture techniques are normally interpreted in terms of SHmin. In the Western Canada Basin, horizontal principal stress directions have been mapped fairly extensively by means of borehole breakouts, augmented by data from fracture orientations and overcoring(7). What has been lacking is equivalent published information on stress magnitudes. Over the past thirty years, thousands of hydraulic fracture jobs have been run in tight or sluggish western Canadian reservoirs and pressure/time records obtained. but these data have not been evaluated and interpreted in terms of in situ stress magnitudes. Mini-frac tests appear to be particularly suitable for estimating the smaller horizontal principal stress, SHmin For this reason, the Geomechanics Group of the Calgary Section of The Petroleum Society of CIM approached 33 operating companies in 1987 and requested the release of speci

Evaluation of Fracturing Results in Deviated Wellbores Through On-Site Measurements

Summary Four adjacent oil wells in the Kuparuk River oil field, with deviated angles of 6°5′, 24°6′, 27°, and 36°7′ from the vertical at the perforations, were analyzed with prefracturing tests. The total fluid volume for these tests varied from 645 to 840 bbl [103 to 134 m3] of either clean lease oil or water-based fracturing fluid at low to intermediate rates (up to 15 bbl/min [2.4 m3/min]). These wells Were subsequently fractured with proppant-laden fluid. A series of instantaneous shut-in pressures (ISIP's) was obtained for each well. ISIP's and fracturing pressures decreased with time in two of the four wells with a relatively high friction pressure at the end of the pumping. A radially propagating fracture from a point source of pressure explains this decreasing pressure with time. The elasticity theory predicts that a fracture in a deviated, cased wellbore should intersect the wellbore at one location. Only when the deviated wellbore azimuth is near that of the fracture orientation does the fracture sweep the entire perforated zone. This observation of the fracture orientation relative to the wellbore azimuth based on the pressure analysis is enhanced further by postfracture temperature surveys. It appears that only a relatively small volume of proppant could be displaced in a deviated wellbore. The degree of deviation, however, did not appear to be a major concern in the treatment size.

Appalachian Stress Study: 1. A detailed description of in situ stress variations in Devonian shales of the Appalachian Plateau

We describe an experiment to measure variations in the state of stress within a horizontally bedded Devonian shale/sandstone/limestone sequence in western New York. A total of 75 stress measurements were made in three wells a kilometer or so apart using a wireline‐supported hydraulic‐fracturing system. The stress profiles indicate that a major drop in horizontal stress level occurs in the generally massive shales. This drop occurs principally across the lowermost member of a group of sand beds and corresponds to an offset in Sh and SH of 3.5 and 9 MPa, respectively. Above the sands, “thrust” regime conditions prevail, although the amount by which Sh exceeds Sv is undetermined since instantaneous shut‐in pressures (ISIPs) were clipped at the level of Sv due to fracture rotation. Below the sands, the regime is strike slip with both horizontal stresses showing lateral uniformity despite substantial variations in topography. The magnitude of Sh in the sand beds themselves and a lower limestone remains at least as great as Sv despite the decline in shale stress. Hence stress contrasts between these beds and neighboring shales become pronounced with depth. The contrast in Sh and SH between the lowermost sand and the immediately underlying shale is at least 6 and 14.5 MPa, respectively. SH levels in the lower strike‐slip regime are about 1.75 times greater than Sh and are less than the value required to initiate slippage on favourably oriented frictional interfaces. For the upper thrust regime and the sand and limestone beds, however, the inferred lower bound on SH is close to the slippage threshold for a Coulomb friction coefficient of 0.6. The orientation of SH is ENE with a standard deviation of 20°. Fracture traces were usually splayed, occasionally spanning 30° of well bore. No systematic correlation between mean orientation and lithology is evident. Significantly different orientations were obtained for adjacent tests in which almost identical ISlPs were observed, suggesting that the fractures quickly reorient themselves to propagate normal to the least principal stress direction. Similarly, vertical traces were observed in those tests where ISIPs apparently reflect Sv, suggesting that rotation to horizontal was rapid.