Leak-off Tests Research Articles

A normal-faulting stress regime in the Bavarian Foreland Molasse Basin? New evidence from detailed analysis of leak-off and formation integrity tests in the greater Munich area, SE-Germany

Leak-off and formation integrity test data from the central part of the Bavarian Foreland Molasse Basin have been investigated in detail to infer information about the stress regime of the Cenozoic basin fill. The detailed analysis of leak-off test data from the Bavarian Foreland Molasse Basin and lithology-dependent analysis of leak-off test and formation integrity data is the first of its kind in a published study. Only test data from shale-rich sequences have been considered. All data yield minimum principal stresses that are smaller than an estimated vertical stress range. In combination with critical stress and frictional equilibrium theory, the data indicate that the stress regime in the greater Munich area and possibly the far-field stress regime of the Bavarian Foreland Molasse Basin are most likely of an extensional nature (normal-faulting stress regime). Under the assumption of frictional equilibrium, a friction coefficient between 0.2 and 0.4 best explains failure in shale-dominated sections of the central part of the Bavarian Foreland Molasse Basin and can be used to estimate the minimum horizontal stress SHmin. However, even in the spatially restricted domain of the greater Munich area the stress regime might vary towards a strike-slip stress regime; most likely in the vicinity of fault zones and/or due to variations in mechanical rock strength. The results of this study have great impact and relevance to improved planning of drilling campaigns, future numerical modelling and the general understanding of the evolution of the Bavarian Foreland Molasse Basin. Additional leak-off tests and extended leak-off tests are recommended to fully unravel the spatial variation and geologic control factors of the stress regime of the entire Bavarian Foreland Molasse Basin.

Technology Update: Mitigation of Wellbore Instability and Mud Losses in High-Depletion Wells

Technology Update Wells in the South China Sea are characterized by high depletion and narrow drilling windows which exponentially increase the risk of incurring severe losses. Mud density, sufficient to maintain well control, typically exceeds the fracture gradient of the clastic and coal formations. Therefore, operators face a dilemma in balancing the need for mud weight (MW) to remain below the fracture gradient to avoid losses, while also providing sufficient density to block influxes into the well. The Alpha field, with a water depth of approximately 26 m (85 ft), is located in Sarawak Basin, offshore Malaysia. This area has historically been classified as a “high risk” drilling environment due to clastic deposition and unstable coal formations. A process is described that stabilized troublesome zones and enabled the wells to be drilled with MWs higher than the maximum density predicted by leak-off tests or formation integrity tests. A drilling process stabilized microfractures and mitigated many of the issues associated with wellbore instability. The use of a wellbore “shield” allowed use of a higher mud weight which eliminated well influxes while simultaneously achieving zero mud losses to the formation. Furthermore, the technology delivered additional wellbore strength to weak formations, allowing the drilling operation to be completed as per plan. Accordingly, the operator significantly reduced the challenges associated with lost circulation, stuck pipe, and well instability, thereby facilitating easier logging and delivering a quality, and less costly, producing well. Problem-Solving Process Offset well analysis. To understand the drilling risks and past issues, the team led by Petronas analyzed the root source of stuck pipe in offset wells. The cost of stuck pipe and wellbore instability was valued at $5.7 million for Offset 1. The analysis determined the stuck pipe event occurred at the coal layer with three main contributing factors: Failure in understanding the coal and weak zone structure prior to drilling Insufficient fracture bridging material while drilling the coal Poor drilling and tripping practices across the coal seam layer that resulted in a stuck bottomhole assembly Predrilling geomechanics analysis. Failures in offset wells were studied through geomechanics analysis to identify the minimum MW requirement for weak zones and the coal layer. The challenge: excessive MW will lead to coal destabilization, whereas too-low MW may lead to borehole collapse. Borehole breakouts were predicted using the geomechanical model and the actual MW used during drilling offset wells. Many of the predicted breakouts were related to weak coal layers in the 12¼-in. sections. An internal geomechanical report also indicated that the drilling problems frequently occurred after reaching section total depth and were likely a result of time-dependent failure mechanisms and/or mud-rock interaction.

Impact of elliptical boreholes on in situ stress estimation from leak-off test data

We developed an inversion technique to determine in situ stresses for elliptical boreholes of arbitrary trajectory. In this approach, borehole geometry, drilling-induced fracture information, and other available leak-off test data were used to construct a mathematical model, which was in turn applied to finding the inverse of an overdetermined system of equations. The method has been demonstrated by a case study in the Appalachian Basin, USA. The calculated horizontal stresses are in reasonable agreement with the reported regional stress study of the area, although there are no field measurement data of the studied well for direct calibration. The results also indicate that 2% of axis difference in the elliptical borehole geometry can cause a 5% difference in minimum horizontal stress calculation and a 10% difference in maximum horizontal stress calculation.

Modeling formation resistivity changes due to invasion and deformation during initial leak-off test build-up

Leak-off tests (LOTs) are performed to determine the strength of a newly drilled formation below a cased interval and to characterize the upper bound of mud weight that can be safely used while drilling the next section, without risk of formation breakdown and lost circulation. In an LOT, drilling mud is pumped into the wellbore, causing the wellbore pressure to increase and exceed the formation pore pressure. During the initial LOT build up, excess pressure in the wellbore causes the surrounding rock to deform and mud filtrate to invade into the formation via porous flow. In this paper, change in formation resistivity around a wellbore during initial LOT build-up has been investigated. Invasion is modeled assuming two-phase radial Darcy flow and deformation using a 3D finite element model. Invasion may result in an exchange of conductive ions between water-based drilling mud and formation water both by diffusion in the direction favored by the concentration gradient of the ions and by convective transport. This process is incorporated into the model by solving the radial convection-diffusion equation for the aqueous phase using a finite difference method. Archie's law is used to determine the formation resistivity. Findings show that the direct effect of deformation on porosity, therefore on formation resistivity during an LOT, is negligibly small even when the formation rock is highly compressible with compressibility in the order of 10−3 psi−1. While salinity solely controls formation resistivity during an LOT conducted in a fully water-saturated interval, water saturation change and salinity change compete to produce a compound effect on formation resistivity of an oil-bearing zone where water saturation varies dynamically due to displacement of formation fluids. Unlike compressibility, the effect of permeability on formation resistivity response is found to be evident and readily observable. While analyzing the formation resistivity responses at various depths of investigation (DOIs), it is found that the effect of DOI on resistivity response can be useful in studying invasion and assessing formation damage during an LOT. In addition to this, through comparing time-lapse resistivity logs at multiple DOIs during an LOT with numerically synthesized resistivity responses, the model promises a novel approach towards determining the permeability of a freshly drilled and unaltered interval.

The state of stress in SW Iran and implications for hydraulic fracturing of a naturally fractured carbonate reservoir

The first part of this study provides an interpretation of the present-day stress state and mechanical parameters for the giant Bangestan reservoir in SW Iran. A total of 28 drilling induced tensile fractures (DITF) and 172 breakouts were mapped in seven wells in the Bangestan reservoir using image logs. The average maximum principal horizontal stress (SH) direction for each well is given a quality ranking according to the World Stress Map (WSM) criteria. The mean orientation of SH finds to be N44°(±9.95°). A correlation is seen between this data and stress orientations from earthquake focal mechanism solution. This suggests that stresses are related to tectonic forces generated by Arabia–Eurasia collision. Estimates of vertical principal stress (Sv) gradients vary between 23.3 and 24.7 kPa/m (1.03–1.09 psi/ft), based on empirical methods and density log data, respectively. Minimum horizontal stress (Sh) gradient estimates vary from 15.2 to 17.4 kPa/m (0.67–0.77 psi/ft) using extended leak-off test (XLOT) and step-rate test results, respectively. Uncertainties remain in estimating SH from acid fracturing in the deep naturally fractured carbonate reservoirs, even though numerous papers have been written on the subject. Herein, an approach called Deformation/Diffusion/Thermal (DDT) is suggested to estimate SH in the Bangestan Reservoir. The method combines poroelastic theories for the circular underground cavities, bilinear theory for fluid flow through the preexisting induced fracture and thermal stress. Using this method, SH gradient is calculated to be 18.9 kPa/m (0.83 psi/ft). For comparison, horizontal stress magnitudes and mechanical parameters were computed from sonic wave velocity using poroelastic-tectonic stress equations over the full reservoir layer thickness. All data have been calibrated with field tests and lab results. The measured SH was in good agreement with the previous analytical solution. The study suggests that the contemporary state of stress in the reservoir is characterized by a normal faulting (NF) stress regime. Next, current and prospective hydraulic fracturing operations in the field are discussed. Based on the NF stress regime, a vertical plane fracture is expected and the wells drilled in the direction of SH are likely to intersect the most natural fractures.

Stress estimation in reservoirs using an integrated inverse method

Estimating the stress in reservoirs and their surroundings prior to the production is a key issue for reservoir management planning. In this study, we propose an integrated inverse method to estimate such initial stress state. The 3D stress state is constructed with the displacement-based finite element method assuming linear isotropic elasticity and small perturbations in the current geometry of the geological structures. The Neumann boundary conditions are defined as piecewise linear functions of depth. The discontinuous functions are determined with the CMA-ES (Covariance Matrix Adaptation Evolution Strategy) optimization algorithm to fit wellbore stress data deduced from leak-off tests and breakouts. The disregard of the geological history and the simplified rheological assumptions mean that only the stress field, statically admissible and matching the wellbore data should be exploited. The spatial domain of validity of this statement is assessed by comparing the stress estimations for a synthetic folded structure of finite amplitude with a history constructed assuming a viscous response.

Fracture gradient prediction: an overview and an improved method

The fracture gradient is a critical parameter for drilling mud weight design in the energy industry. A new method in fracture gradient prediction is proposed based on analyzing worldwide leak-off test (LOT) data in offshore drilling. Current fracture gradient prediction methods are also reviewed and compared to the proposed method. We analyze more than 200 LOT data in several offshore petroleum basins and find that the fracture gradient depends not only on the overburden stress and pore pressure, but also on the depth. The data indicate that the effective stress coefficient is higher at a shallower depth than that at a deeper depth in the shale formations. Based on this finding, a depth-dependent effective stress coefficient is proposed and applied for fracture gradient prediction. In some petroleum basins, many wells need to be drilled through long sections of salt formations to reach hydrocarbon reservoirs. The fracture gradient in salt formations is very different from that in other sedimentary rocks. Leak-off test data in the salt formations are investigated, and a fracture gradient prediction method is proposed. Case applications are examined to compare different fracture gradient methods and validate the proposed methods. The reasons why the LOT value is higher than its overburden gradient are also explained.

State of stress in the Illinois Basin and constraints on inducing failure

The stress regime in the Illinois Basin was investigated to assess how the rock column might respond to the injection of fluids, including coproduced formation brines and supercritical CO2.This response is a concern because injection practices could increase pore fluid pressure and potentially induce seismicity. Data were collected to determine the magnitude and orientation of a three-component stress field: vertical stress (Sv) and minimum (Sh) and maximum (SH) horizontal stresses. The Sv was evaluated with a six-layer lithostratigraphic column. A two-layer pressure–depth Sv model was generated for the central part of the basin, and a single pressure gradient model was constructed for the surrounding region. In the central part of the basin, the Sv gradient is 24.9 MPa/km (1.11 psi/ft) to a depth of 2134 m (7000 ft), followed by a gradient of 27.1 MPa/km (1.20 psi/ft) below 2134 m (7000 ft). For the area surrounding the deep basin, the Sv gradient was 25.5 MPa/km (1.13 psi/ft). The Sh was evaluated from multiple data sources, primarily hydraulic fracture records or extended leak-off tests. The Sh gradient calculations ranged from 24.1 to 27.3 MPa/km (1.07 to 1.21 psi/ft). The Sh values for the basal Paleozoic clastic units are lower than those for units in the overlying horizons. The SH was based on a critically stressed model yielding values between 40.0 and 82.6 MPa/km (1.77 to 3.65 psi/ft). Stress orientation data for the Illinois Basin were collected from multiple sources. The orientation of SH across the study area is relatively uniform in strike at approximately N60°E. Marked deviations in SH result from localized structural discontinuities.

Uncertainties in the estimation of in situ stresses: effects of heterogeneity and thermal perturbation

In situ stress directions and magnitudes in subsurface are commonly estimated using two different methods: (1) borehole break-out—drilling-induced fracture interpretation complemented by extended leak-off tests; (2) stress estimation from acoustic measurements using advanced wireline tools. Both methods use stress perturbations around boreholes to estimate far field stresses employing Kirsch’s equations, which are only valid for boreholes aligned with one of the principal stresses, linear elastic deformation and homogeneous isotropic materials. Furthermore, the original stress state may have been altered by drilling-mud-circulation induced temperature changes. Using heuristic models including heterogeneity, this study investigates potential errors in the estimation of far-field stress due to (a) the generalisation of Kirsch’s equations to heterogeneous media and (b) plausible temperature perturbations. First, errors due to uncertainties in measuring wave slowness are analysed for an idealised homogeneous material. Second, errors due to application of Kirsch’s equations are investigated considering potential effects of frictional interfaces between layers, pore pressure in the rock matrix and thermal perturbations induced by drilling for example cases. To analyse stress in these complex scenarios finite element analysis was used, revealing strong effects of lithological and thermal variations. Stress magnitude was amplified by stiff layers and was attenuated by soft ones. At layer interfaces, substantial changes in stress orientation occurred. Kirsch’s equations for the considered cases resulted in errors in far field stresses as large as 44% in the magnitude and 90° in orientations. An uncertainty propagation analysis indicated a high accuracy of acoustic estimates for homogenous materials. However, a dramatic impact of small-scale heterogeneity may not be resolved by the logging process.

Full waveform acoustic data as an aid in reducing uncertainty of mud window design in the absence of leak-off test

Creating a mechanical earth model (MEM) during well planning, and real-time revision has proven to be extremely valuable to reach the total depth of well safely with least instability problems. One of the major components of MEM is determining horizontal stresses with reasonable accuracy. Leak-off and minifrac tests are commonly used for calibrating horizontal stresses. However, these tests are not performed in many oil and gas wellbores since the execution of such tests is expensive, time-consuming and may adversely impact the integrity of a wellbore.In this study, we presented a methodology to accurately estimate the magnitudes and directions of horizontal stresses without using any leak-off test data. In this methodology, full waveform acoustic data is acquired after drilling and utilized in order to calibrate maximum horizontal stress. The presented methodology was applied to develop an MEM in a wellbore with no leak-off test data. Processing of full waveform acoustic data resulted in three far-field shear moduli. Then based on the acoustoelastic effect, maximum horizontal stress was calibrated. Moreover, maximum horizontal stress direction was detected using this methodology through the whole wellbore path. The application of this methodology resulted in constraining the MEM and increasing the accuracy of the calculated horizontal stresses, accordingly a more reliable safe mud weight window was predicted. This demonstrates that the presented methodology is a reliable approach to analyze wellbore stability in the absence of leak-off test.

In-situ stress state in the Linxing region, eastern Ordos Basin, China: Implications for unconventional gas exploration and production

The Carboniferous and Permian sedimentary rocks (mainly the Shanxi and Taiyuan formations) in the Linxing region, eastern Ordos Basin, China, host a significant volume of unconventional gas resources (coalbed methane, shale gas and tight sandstone gas). Currently, the in-situ stress state is poorly understood but knowledge of this is extremely important for a range of applications, such as gas exploration and production, fracture stimulation and wellbore stability. The maximum horizontal stress (SHmax), minimum horizontal stress (Shmin) and vertical stress (Sv) magnitudes, and the SHmax orientation in the Linxing region were systematically analyzed for the first time in the present study, which can provide a reference for subsequent numerical simulation and hydraulic fracturing design. Based on borehole breakouts and drilling-induced tensile fractures interpreted from borehole imaging logs, the SHmax orientation rotates from ∼NEE-SWW-trending in the southern part to ∼ NWW-SEE-trending in the northern part of the Linxing region. Both conventional logs and extended leak-off tests were used for stress magnitude determination. The results revealed three types of in-situ stress fields (Sv > SHmax > Shmin, SHmax > Sv > Shmin and SHmax > Sv ≈ Shmin), and a dominant strike-slip stress regime (SHmax > Sv ≥ Shmin) was found for the entire well section in the target Shanxi Formation and Taiyuan Formation in the Linxing region. In addition, differential stress increased with depth in the Linxing region, which indicates that wellbore instability might be a potentially significant problem when drilling wells that are vertical or ∼ N-S-trending.

In situ stress variations associated with regional changes in tectonic setting, northeastern Brooks Range and eastern North Slope of Alaska

ABSTRACT The northeastern Brooks Range of northern Alaska is an active, north-directed fold-and-thrust belt that is advancing on the Barrow arch and the north-facing passive margin of the Arctic Basin. Density logs, leak-off tests, and mud-weight profiles from 57 wells from the northeastern North Slope were used to determine the magnitude of the present-day in situ stresses and document significant regional lateral and vertical variations in relative stress magnitude. Preliminary analysis of the in situ stress magnitudes indicates two distinct stress regimes across this region of Alaska. Areas adjacent to the eastern Barrow arch exhibit both strike-slip and normal stress regimes. This in situ stress regime is consistent with fault patterns in the subsurface and with north–south extension along the Barrow arch and the northern Alaska margin. To the south in and near the northeastern Brooks Range thrust front, in situ stress magnitudes indicate that an active thrust-fault regime is present at depths up to 6000 ft (1829 m). This is consistent with the fold-and-thrust structures in surface exposures and in the subsurface. However, at depths greater than 6000 ft (1829 m), the relative in situ stress magnitudes indicate a change to a strike-slip regime. This observation is consistent with the few earthquake focal mechanisms in the area and suggests deep north-northeast–oriented strike-slip faults may underlie the western margin of the northeastern Brooks Range.

Characterising the present-day stress regime of the Georgina Basin

ABSTRACTThe onshore Georgina Basin in northern Australia is prospective for unconventional hydrocarbons; however, like many frontier basins, it is underexplored. A well-connected hydraulic fracture network has been shown to be essential for the extraction of resources from the tight reservoirs that categorise unconventional plays, as they allow for economic flows of fluid from the reservoir to the well. One of the fundamental scientific questions regarding hydraulic stimulation within the sub-surface of sedimentary basins is the degree to which local and regional tectonic stresses act as a primary control on fracture propagation. As such, an understanding of present-day stresses has become increasingly important to modern petroleum exploration and production, particularly when considering unconventional hydrocarbon reservoirs. This study characterises the regional stress regime in the Georgina Basin using existing well data. Wellbore geophysical logs, including electrical resistivity image logs, and well tests from 31 petroleum and stratigraphic wells have been used to derive stress magnitudes and constrain horizontal stress orientations. Borehole failure features interpreted from wellbore image and caliper logs yield a maximum horizontal stress orientation of 044°N. Integration of density log data results in a vertical stress gradient of 24.6 MPa km–1. Leak-off and mini-fracture tests suggest that this is the minimum principal stress, as leak-off values are generally shown to be at or above the magnitude of vertical stress. The maximum horizontal stress gradient is calculated to be in the range of 31.3–53.9 MPa km–1. As such, a compressional stress regime favouring reverse/reverse–strike-slip faulting is interpreted for the Georgina Basin.

Integrated electromagnetic data investigation of a Mesozoic CO2 storage target reservoir-cap-rock succession, Svalbard

Recently acquired time-domain electromagnetic (TEM) and magnetotelluric (MT) data sets are utilized in the first electromagnetic (EM) characterization of a geological CO2 storage target site in Adventdalen, Arctic Norway. Combining the two EM data sets enabled to resolve the electrical resistivity structure of the target site better than either of the methods alone. 2D inverting the MT data in the audio period interval (0.003–1s) with supporting input derived from the TEM data (0.01–10ms) provided a geologically meaningful resistivity model that included information not previously evident from existing seismic and borehole data. The ca. 1.8×1km 2D resistivity model displays a laterally constrained highly conductive anomaly (ca. 10Ωm) at about 400–500m depth, where reflectors of a parallel seismic section are concealed and core samples indicate a highly fractured décollement zone formed during Paleogene compression. The base of the permafrost is imaged at ca. 200m depth. Synthetic inversion tests, however, suggest that this may be exaggerated by tens of meters, due to a thin conductive layer present approximately between 10 and 25m depth. The resistivity model does not give indication for a fluid pathway we can connect to leakage, in line with water injection and leak-off tests in the reservoir and cap-rock, both of which indicate a sealing shale-dominated cap-rock separating an over-pressured compartment above the sealing shale from a severely under-pressured reservoir interval. The results we present indicate the advantage of integrating EM exploration techniques in a CO2 reservoir-cap-rock study to obtain a more complete picture.

Estimating pore fluid pressure-stress coupling

Fracture Pressure (FP) prediction is a vital component in well planning for safe drilling in high pressure areas, in the estimation of seal capacity and seal breach risk analysis, for fluid injection and in fracture stimulation for oil/gas recovery from tight reservoirs and mature source rocks.Coupling of pore fluid pressure (PP) and FP at basin-scale has been recognised for several decades, with coupling ratio values mostly between 0.46 and 0.87, i.e. for every 10 MPa of PP increase at constant depth, FP increases by 4.6–8.7 MPa. These values are similar to estimates for reduction of FP with reservoir depletion of an oil/gas field during production. Poroelasticity has been suggested as the principal reason for coupling. Most previous coupling values were generated by examination of pressure gradients. A new method to estimate pore fluid pressure-stress coupling is proposed which plots the measured value of FP from a Leak Off Test (LOT) minus the expected FP value on the trend for normal pressures (termed the Fracture Pressure Residual, FPr) against overpressure (OP), which is the magnitude of PP above normal at the same depth. The coupling value is now the slope of FPr against OP. FPr:OP coupling values from 11 global basin datasets range from 0.24 to 0.43, approximately half the previous quoted basin-scale coupling values.A pressure-depth model for rapid deposition on a continental margin, with OP exclusively generated by disequilibrium compaction and no change in effective stress in the overpressured section, represents a base case for compaction OP without poroelasticity. This model helps to reveal (1) that coupling values vary with the ratio of FP to lithostatic pressure (Sv); (2) since the 11 case study coupling values exceed the base case, one or more other (minor) coupling mechanisms are involved, potentially including poroelasticity; (3) values may be independent of tectonic environment; (4) one case study involving carbonate (chalk) is within the same range as those from siliciclastic sediments, and (5) the high coupling pore pressure-stress coupling values in the literature result from using fluid and fracture gradients including the shallow data where PP is normal, which distort the analysis.

Characterization of In Situ Stress State and Joint Properties from Extended Leak-Off Tests in Fractured Reservoirs

AbstractCharacterization of geomechanical parameters in naturally fractured reservoirs remains one of the most challenging tasks in civil, mining, and petroleum engineering. Extended leak-off tests (XLOTs) are generally carried out in new wells to obtain in situ stresses for hydraulic fracture-treatment design and well-trajectory optimization in petroleum engineering. The largest and smallest principal in situ stresses can be calculated by shut-in/closure pressure and breakdown/reopening pressure of XLOTs. However, in situ stresses obtained from XLOTs in the traditional theoretical framework are not completely correct because XLOTs still keep the same test collocations as leak-off tests. In addition, the traditional method cannot be used to simultaneously calculate other parameters beyond in situ stresses. Given these challenges, a hybrid artificial neural network (ANN)–genetic algorithm (GA) method was tested for identification of the principal in situ stresses and joint parameters. First, XLOTs were per...

In situ stress magnitude and rock strength in the Nankai accretionary complex: a novel approach using paired constraints from downhole data in two wells

We present a method to simultaneously constrain both far-field horizontal stress magnitudes (S hmin and S Hmax) and in situ rock unconfined compressive strength (UCS), using geophysical logging data from two boreholes located 70 m apart that access the uppermost accretionary prism of the Nankai subduction zone . The boreholes sample the same sediments and are affected by the same tectonic stress field, but were drilled with different annular pressures, thus providing a unique opportunity to refine estimates of both in situ stress magnitudes and rock strength. We develop a forward model to predict the angular width of compressional wellbore failures (borehole breakouts), and identify combinations of S Hmax and UCS that best match breakout widths observed in resistivity images from the two boreholes. The method requires knowledge of S hmin, which is defined by leak-off tests conducted during drilling. Our results define a normal to strike-slip stress regime from 900 to 1386 m below seafloor, consistent with observations from seismic and core data. Our analysis also suggests that in situ values of UCS are generally slightly lower that commonly assumed on the basis of published empirical relations between UCS and P-wave velocity.

Incompatible stress regimes from geological and geomechanical datasets: Can they be reconciled? An example from the Carnarvon Basin, Western Australia

Knowledge of the in-situ stress field is essential in petroleum basins, as it exerts a prime control over seal integrity, fracture stimulation, wellbore stability, and fluid flow. Previous geomechanical analysis of Australia's Carnarvon Basin, the continent's premier hydrocarbon region, highlights a normal to strike-slip fault stress regime. However, neotectonic evidence and contemporary seismicity suggest the possibility of a strike-slip to reverse-fault stress regime. We attempt to reconcile these conflicting datasets through new analysis of the in-situ stresses; Principal stress magnitudes and orientations were defined with data from 76 previously unanalysed petroleum wells. Wellbore image logs yield a maximum horizontal stress orientation of 113°N, consistent with modelling of the stress-field throughout the Indo-Australian Plate. Vertical stress magnitudes are estimated to range from 20MPakm−1 to 22.4MPakm−1. Leak-off tests (LOT) from 42 wells are analysed using two methodologies (one assuming tensile failure as traditionally accepted, the other assuming shear failure as outlined by Couzens-Schultz and Chan, 2010) and result in two different sets of horizontal stress magnitude estimates. Traditional interpretation of LOTs results in a minimum horizontal stress gradient of 16.8MPakm−1 and a maximum horizontal stress gradient of 21.8MPakm−1. The new method for LOT interpretation results in a minimum horizontal stress gradient of 18.1MPakm−1 and a maximum horizontal stress gradient of 25.4MPakm−1. Inclined natural fractures observed at LOT depths supports application of the new method of LOT interpretation. Traditional interpretation of stress magnitudes implies a normal to strike-slip fault stress regime, while the new method implies a strike-slip fault stress regime. This latter interpretation is favoured by the authors, as it allows for a reconciliation of the geological and geomechanical datasets. The assessment undertaken herein allows for reinterpretation of stress magnitudes in seismically-active basins hosting differing geomechanical and neotectonic regimes, potentially altering existing understanding of seal integrity, fracture stimulation, wellbore stability, and fluid flow.

A Review on Fracture-Initiation and -Propagation Pressures for Lost Circulation and Wellbore Strengthening

Summary Fracture-initiation pressure (FIP) and fracture-propagation pressure (FPP) are both important considerations for preventing and mitigating lost circulation. For significant fluid loss to occur, a fracture must initiate on an intact wellbore or reopen on a wellbore with pre-existing fractures, and then propagate into the far-field region. Wellbore-strengthening operations are designed to increase one or both of these two pressures to combat lost circulation. Currently, some theoretical models assume that FIPs and FPPs are only functions of in-situ stress and rock-mechanical properties. However, as demonstrated by numerous field and laboratory observations, they are also highly related to drilling-fluid properties and to interactions between the drilling fluid and formation rock. This paper discusses the mechanisms of lost circulation and wellbore strengthening, with an emphasis on factors that can affect FIP and FPP. These factors include microfractures on the wellbore wall, in-situ-stress anisotropy, pore pressure, fracture toughness, filter-cake development, fracture bridging/plugging, bridge location, fluid leakoff, rock permeability, pore size of rock, mud type, mud solid concentration, and critical capillary pressure. The conclusions of this paper include information seldom considered in lost-circulation studies, such as the effect of microfractures on FIP and the effect of capillary forces on FPP. Research results described in this paper may be useful for lost-circulation mitigation and wellbore-strengthening design, as well as hydraulic-fracturing design and leakoff-test (LOT) interpretation.

Geomechanical modeling - workflow and Applications

This work aimed to present a detailed workflow for building a geomechanical model. For a case study, the workflow is then applied to a horizontal well X. The first step in building a geomechanical model is gathering data regarding well information (tubing, casing, deviation…), geological information (type of fault, permeability, reservoir radius, skin…), logs data (density, resistivity, sonic, caliper…), in-situ test data (leak-off test, formation test,…) and core data (tensile strength test, fracture toughness test, tri-axial test…). The second step is to build the geomechanical model using data analysis so that information about state of stress (vertical and principal horizontal stresses, pore pressure, concentration stress around wellbore) and rock mechanical properties (unconfined compressive strength, tensile strength, fracture toughness, Young modulus, Poisson ratio) can be determined. Moreover, the differences in data analysis for vertical and horizontal wells were also mentioned in this work. Furthermore, it is evident that the more data we get, the more accurately a geomechanical model can be built. However, in reality, not all necessary data can be obtained, so this work also explained how to draw the most information from available data so that we can minimize the number of assumptions and uncertainties. An accurate geomechanical model is very essential for others works such as well bore stability or performance prediction of a well stimulation technique. The case study of this work presented the geomechanical modeling for the well X. The paper then presented the application of geomechanical modeling for the Evaluation of High Energy Gas Fracturing performance as well as for Sand Control analysis.