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

2018 ◽  
Vol 140 (12) ◽  
Author(s):  
Sherif M. Kholy ◽  
Ahmed G. Almetwally ◽  
Ibrahim M. Mohamed ◽  
Mehdi Loloi ◽  
Ahmed Abou-Sayed ◽  
...  
Keyword(s):  
Function Analysis ◽  
Injection Pressure ◽  
In Situ Stress ◽  
New Technique ◽  
Strong Impact ◽  
Stress Increment ◽  
Injection Zone ◽  
Fracture Closure ◽  
Slurry Injection

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.

Geomechanical Modeling Based on the First Success of Micro-Frac Tests in the Nahr Umr Formation in Offshore Abu Dhabi

2021 ◽  
Author(s):  
Kimikazu Tsusaka ◽  
Tatsuya Fuji ◽  
Michael Alexander Shaver ◽  
Denya Pratama Yudhia ◽  
Motohiro Toma ◽  
...  
Keyword(s):  
In Situ Stress ◽  
Oil Field ◽  
Mechanical Anisotropy ◽  
Borehole Wall ◽  
Abu Dhabi ◽  
Stress Regime ◽  
Lost Circulation ◽  
Fracture Closure ◽  
Allowable Range

Abstract In the studied oil field in Offshore Abu Dhabi, the intermediate hole section has suffered from borehole instability and lost circulation in the higher inclination holes. Borehole instability occurs in the Nahr Umr formation. Lost circulation occurs in the Salabikh formation. This study aims to develop geomechanical model and to analyze mud weight (MW) for successful drilling through the two problematic formations in the studied oil field. In the Salabikh formation, spatial distribution of lost circulation pressure in hundreds of wells in the whole field was analyzed. The fracture closure pressure was also evaluated based on the extended leak-off test and fracture interpretation by image logging. In the Nahr Umr formation, Micro-Frac tests in a 6" hole were implemented to evaluate the minimum in-situ stress. This was the first direct measurement of the in-situ stress in the shale. The magnitude of SHMAX was back-analyzed based on the hole geometry using interpretation of six-arm caliper and analytical solution in the two key locations. This study clarified that severe lost circulation in the crest area was likely to occur due to reactivation of the pre-existing fractures in the Salabikh formation. The lost circulation pressure was found to be approximately 1.4 SG. The study also revealed that the in-situ stress regime in the Nahr Umr formation varied from the crest to flank areas. The crest and flank areas are reverse and nearly normal faulting stress regimes, respectively. Its transition area is strike-slip faulting stress regime. The regional difference in in-situ stress regime depends on the extent of mechanical anisotropy of the shale and the magnitude of tectonic strains. By integrating the results, with respect to the borehole stability analysis in the Nahr Umr formation, instead of a conventional lower hemisphere representation of the required MW based on failure width at borehole wall, the study analyzed the geometry of the failure area around the borehole wall under the allowable range of MW constrained by the lost circulation pressure in the Salabikh formation. As a result, the borehole failure cannot be avoided in any hole inclination in the Nahr Umr formation under the allowable range of MW to prevent severe lost circulation in the Salabikh formation. Therefore, appropriate practice to transport cavings is one of the key elements for safe drilling in higher hole inclination across the intermediate hole section in the studied oil field.

Multiple In-Situ Stress Measurements in Carbonate Reservoirs for CO2 Injection Capability Assessment and Far-Field Strain Calibrations

2022 ◽  
Author(s):  
Javier Alejandro Franquet ◽  
Viraj Nitin Telang ◽  
Hayat Abdi Ibrahim Jibar ◽  
Karem Alejandra Khan
Keyword(s):  
Oil Recovery ◽  
Fracture Initiation ◽  
In Situ Stress ◽  
Carbonate Reservoirs ◽  
Lateral Strain ◽  
Co2 Injection ◽  
Far Field ◽  
Pressure Derivative ◽  
Fracture Closure

Abstract The scope of this work is to measure downhole fracture-initiation pressures in multiple carbonate reservoirs located onshore about 50 km from Abu Dhabi city. The objective of characterizing formation breakdown across several reservoirs is to quantify the maximum gas and CO2 injection capacity on each reservoir layer for pressure maintenance and enhance oil recovery operations. This study also acquires pore pressure and fracture closure pressure measurements for calibrating the geomechanical in-situ stress model and far-field lateral strain boundary conditions. Several single-probe pressure drawdown and straddle packer microfrac injection tests provide accurate downhole measurements of reservoir pore pressure, fracture initiation, reopening and fracture closure pressures. These tests are achieved using a wireline or pipe-conveyed straddle packer logging tool capable to isolate 3 feet of openhole formation in a vertical pilot hole across five Lower Cretaceous carbonate reservoirs zones. The fracture closure pressures are obtained from three decline methods during the pressure fall-off after fracture propagation injection cycle. The three methods are: (1) square-root of the shut-in time, (2) G-Function pressure derivative, and (3) Log-Log pressure derivative. The far-field strain values are estimated by multi-variable regression from the microfrac test data and the core-calibrated static elastic properties of the formations where the stress tests are done. The reservoir pressure across these carbonate formations are between 0.48 to 0.5 psi/ft with a value repeatability of 0.05 psi among build-up tests and 0.05 psi/min of pressure stability. The formation breakdown pressures are obtained between 0.97 and 1.12 psi/ft over 5,500 psi above hydrostatic pressure. The in-situ fracture closure measurements provide the magnitude of the minimum horizontal stress 0.74 - 0.83 psi/ft which is used to back-calculate the lateral strain values (0.15 and 0.72 mStrain) as far-field boundary condition for subsequent geomechanical modeling. These measurements provide critical subsurface information to accurately predict wellbore stability, hydraulic fracture containment and CO2 injection capacity for effective enhance oil recovery within these reservoirs. This in-situ stress wellbore data represents the first of its kind in the field allowing petroleum and reservoir engineers to optimize the subsurface injection plans for efficient field developing.

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

Energies ◽  
2020 ◽  
Vol 13 (21) ◽  
pp. 5842
Author(s):  
Pengju Xing ◽  
John McLennan ◽  
Joseph Moore
Keyword(s):  
Geothermal Energy ◽  
Stress Gradient ◽  
In Situ Stress ◽  
Perspective View ◽  
Step Rate ◽  
Stress Measurements ◽  
Closure Stress ◽  
Fracture Closure ◽  
In Situ Stress Measurements

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.

THE RECOGNITION AND ALLEVIATION OF COMPLEXITY WITH HYDRAULIC FRACTURING ONSHORE AUSTRALIA

2000 ◽  
Vol 40 (1) ◽  
pp. 469 ◽  
Author(s):  
M.M. Rahman ◽  
M.K. Rahman ◽  
S.S. Rahman
Keyword(s):  
Injection Pressure ◽  
Cost Effective ◽  
In Situ Stress ◽  
Shear Dilation ◽  
Fracture Simulation ◽  
Fracture Complexity ◽  
Contractual Obligations ◽  
Remedial Work ◽  
Treatment Pressure

Increasingly demanding contractual obligations and more cost-effective technology has led to the widespread use of hydraulic fracture treatments of wells onshore Australia. Whilst historically confined to low permeability, marginal fields, the majority of natural gas wells in some areas of onshore Australia are now routinely hydraulically fractured. However, a number of wells in localised regions have displayed treatment difficulties. Such wells consistently display common symptoms, such as the inability to inject proppant at required concentrations without exceeding surface injection pressure limitations. Fracture treatments on these wells are often prematurely terminated (or 'screen-out'), mainly because of near-wellbore fracture complexity. Such wells invariably display poor post-stimulation productivity.This paper describes the evaluation of reservoirs on the basis of in-situ stress and their propensity for fracture complexity. Simple, recognisable treatment pressure signatures, which indicate the presence of near-wellbore tortuosity, are presented. A conventional single, planar fracture simulation model confirms the presence of fracture tortuosity. Proppant-free shear dilation, herein referred to as a 'water-frac', has been analysed as an alternative fracture treatment in which natural fractures are inflated to interconnect with each other, forming a conduit for hydrocarbon flow. This alleviates near- wellbore fracture complexity and may avoid the expenditure of hundreds of thousands of dollars on sub- optimal fracture treatments or remedial work.

Perfecting Straddle Packer Microfrac Stress Contrast Measurements for Hydraulic Fracturing Design in UAE Tight Oil Reservoir

2021 ◽  
Author(s):  
Javier Franquet ◽  
A. N. Martin ◽  
Viraj Telaj ◽  
Hamad Khairy ◽  
Ahmed Soliman ◽  
...  
Keyword(s):  
Stress Testing ◽  
In Situ Stress ◽  
Stress Profile ◽  
Oil Reservoir ◽  
Stress Tests ◽  
Reservoir Stimulation ◽  
Fracture Closure ◽  
Dense Zone ◽  
Stress Contrast

Abstract The objective of this work was to quantify the in-situ stress contrast between the reservoir and the surrounding dense carbonate layers above and below for accurate hydraulic fracturing propagation modelling and precise fracture containment prediction. The goal was to design an optimum reservoir stimulation treatment in a Lower Cretaceous tight oil reservoir without fracturing the lower dense zone and communicating the high-permeability reservoir below. This case study came from Abu Dhabi onshore where a vertical pilot hole was drilled to perform in-situ stress testing to design a horizontal multi-stage hydraulic fractured well in a 35-ft thick reservoir. The in-situ stress tests were obtained using a wireline straddle packer microfrac tool able to measure formation breakdown and fracture closure pressures in multiple zones across the dense and reservoir layers. Standard dual-packer micro-injection tests were conducted to measure stresses in reservoir layers while single-packer sleeve-frac tests were done to breakdown high-stress dense layers. The pressure versus time was monitored in real-time to make prompt geoscience decisions during the acquisition of the data. The formation breakdown and fracture closure pressures were utilized to calibrated minimum and maximum lateral tectonic strains for accurate in-situ stress profile. Then, the calibrated stress profile was used to simulate fracture propagation and containment for the subsequent reservoir stimulation design. A total 17 microfrac stress tests were completed in 13 testing points across the vertical pilot, 12 with dual-packer injection and 5 with single-packer sleeve fracturing inflation. The fracture closure results showed stronger stress contrast towards the lower dense zone (900 psi) in comparison with the upper dense zone (600 psi). These measurements enabled the oilfield operating company to place the lateral well in a lower section of the tight reservoir without the risk of fracturing out-of-zone. The novelty of this in-situ stress testing consisted of single packer inflations (sleeve frac) in an 8½-in hole in order to achieve higher differential pressures (7,000 psi) to breakdown the dense zones. The single packer breakdown permitted fracture propagation and reliable closure measurements with dual-packer injection at a lower differential reopening pressure (4,500 psi). Microfracturing the tight formation prior to fluid sampling produced clean oil samples with 80% reduction of pump out time in comparison to conventional straddle packer sampling operations. This was a breakthrough operational outcome in sampling this reservoir.

Dimensions and Degree of Containment of Waterflood-Induced Fractures from Pressure Transient Analysis

2005 ◽  
Vol 8 (05) ◽  
pp. 377-387 ◽  
Author(s):  
Paul J. van den Hoek
Keyword(s):  
Water Injection ◽  
In Situ Stress ◽  
Fracture Face ◽  
Injection Wells ◽  
Test Analysis ◽  
Pressure Transient ◽  
Type Curves ◽  
Fracture Closure ◽  
Induced Fractures

Summary It is well established within the industry that injection of (produced)water almost always takes place under fracturing conditions. Particularly when large volumes of very contaminated water are injected—either for voidage replacement or disposal—large fractures may be induced over time. This paper aims to provide a methodology for injection-falloff (IFO) test analysis of fractured (produced) water-injection wells. Some essential elements of IFO for fractured water injectors include the closing fracture, (early)transient elliptical reservoir-fluid flow, finite fracture conductivity, and fracture face skin. An exact semianalytical solution is presented to the fully transient elliptical fluid-flow equation around a closing fracture with finite conductivity, fracture face skin, and multiple mobility zones in the reservoir surrounding the fracture. This solution also captures the case that during closure, the fracture is generally shrinking from adjacent geological layers under higher in-situ stress. Based on this solution, type curves of the dimensionless bottomhole pressure as a function of dimensionless time are provided, covering both the period during fracture closure/shrinkage and the period after fracture closure. The shape of these type curves is studied as a function of the different relevant parameters, in particular the fracture compliance, the height of in-situ stress contrasts, fracture face skin, fracture closure time, and injection period. It is shown how the fracture length and height and the degree of fracture containment (in combination with the heights of the stress contrasts) can be derived from these types of curves. It is also demonstrated that the analyses based on the storage flow and linear formation flow regimes need to be integrated into one analysis method to obtain consistent results. Finally, the concepts developed in this paper are applied to a number of field examples, in which the dimensions and degree of containment of the induced fractures are derived from the analysis of the IFO data. Introduction IFO test analysis offers one of the cheapest ways to determine the dimensions of induced fractures. Unfortunately, hardly any work has been carried out to date to provide a methodology for interpreting the pressure-transient data of fractured water-injection wells. This contrasts with the vast amount of work that has been carried out in the area of pressure-transient analysis for wells with propped fractures. Both pressure-transient tests during hydraulic fracture stimulation (called"minifrac tests"; see Ref. 1) and pressure-transient tests during production after stimulation (i.e., buildup tests; see Refs. 2 through 5) have been studied extensively. The theories as developed in Refs. 1 through 5 by now are well-accepted "textbook" methodologies. This paper deals with the subject of pressure-falloff analysis on fractured water-injection wells. In this area, the situation is entirely different from the one above in the sense that until recently, there existed no practical methodology dedicated to pressure-falloff analysis on fractured water injectors. The very limited interest in falloff-test analysis on fractured water injectors may well be related to the fact that historically, most operators have been unaware that their water injectors are fractured. Only in recent years has this situation started to change. Unfortunately, one of the consequences of the lack of a dedicated method of analysis is that falloff tests on injectors are generally interpreted in the wrong way, even if one realizes that they are fractured. Typically, such interpretations lead to wellbore-storage coefficients that can be up to orders of magnitude too high, and to fracture lengths based only on analysis of the linear formation flow period (see Ref. 10). The objective of our study is to fill the gap as described above (i.e., to provide a dedicated interpretation methodology for falloff tests on fractured water injectors). In a recent paper, we presented a novel interpretation methodology for falloff tests on fractured water injectors. This methodology is based on exact 2D solutions to the problem of pressure falloff around fractured water injectors for different boundary conditions. The most important stepforward of Ref. 6 is that it allows the determination of fracture length from a consistent combined analysis of the storage and linear-to-pseudo radial formation flow periods, and of fracture height from a consistent combined analysis of the storage and pseudoradial flow periods. Thus, uncertainties in the determination of fracture dimensions from falloff-test analysis are reduced. In the course of analyzing a variety of field cases, we found, based on the signature of field falloff-test data, that in many cases, the induced fractures must have penetrated into adjacent higher-stress zones. Therefore, the methodology as developed in Ref. 6 was extended to cater to this effect, with the objective being to enable derivation of local in-situ stress contrasts from falloff-test interpretation. This extension forms the main subject of the current paper. The paper is organized as follows. The next section presents the pressure-transient solution for a closing and shrinking water-injection fracture, including a brief recap of the main concepts presented in Ref. 6. The third section presents in some detail the shape of the pressure-transient type curves for a closing/shrinking fracture as a function of the different relevant parameters, such as the fracture compliance and the height of in-situ stress contrasts. Subsequently, this method is applied to four field examples. Finally, the last section presents our conclusions.

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