Mini-frac Tests Research Articles

Building 1D Mechanical Earth Model for Subba Oilfield in Iraq

At the Subba oil field, wellbore stability is the main concern while drilling. The wellbore's instability causes several issues, including: (inefficient hole cleaning, tight hole, stuck pipe, mud losses, caving, bad cementing, and well kick or blowout). This increases Non-Productive Time (NPT) and well-drilling costs; hence the operator's main goal is to create a drilling program that reduces these problems and therefore reduce drilling cost. The study aims to build a 1D mechanical earth model to predict the wellbore failure and design optimum mud weight to improve the drilling efficiency for future wells. The model includes pore pressure, stress state, and rock mechanical parameters (such as UCS, angle of friction, Young-Modulus, and Poisson-Ratio). To achieve this aim, the study utilised offset well data including log data (Gama-Ray Logs (GR), Caliper Logs (CALI), Density Logs (RHOZ), and Compressional Sonic (DTCO) and Shear Sonic (DTSM)), Core tests, Mini-frac field tests, Drilling Reports, Mud Reports, and Mud Log Reports (master log) to estimate and calibrate the profiles of formation pore pressure, rock mechanical properties, and in-situ stresses. The 1D mechanical earth model was built using the Excel program for three wells data set, where all the necessary parameters to create the model was calculated, calibrated for the calculated variables with core data and pressure test points, and finally the safe mud window was detected. The results showed that the Eaton Slowness method to predict pore pressure perfectly matches the pressure test points. The most common fault regimes in the Subba oilfield are normal and strike-slip faults. The Modified Lade criteria showed a compatible match with drilling events and calliper log in predicting the failure zones, so it is the best criterion in determining minimum and maximum mud weight. Based on the results of this study and in comparison with the mud window used in drilling operations in the field, it is necessary to change the mud window used in drilling and adopt the safe MWW of this study in drilling new wells in this field and the area adjacent to the field.

Constraining maximum horizontal stress using wellbore breakouts — A case study from the Ordovician tight reservoir of the northeastern Oued Mya Basin, Algeria

In this study, we interpret the maximum horizontal stress (SHmax) azimuth from the breakout positions of the wellbore and attempt to constrain the SHmax gradient based on the interpreted breakout width. A cumulative of 110 m of breakouts are deciphered within the Ordovician Hamra Quartzite interval of the Oued Mya Basin from a 138 m acoustic image log. These breakouts are ranked as “A-Quality” following the World Stress Map ranking guidelines. We infer a mean SHmax orientation of N28°E ± 8°. Following the frictional faulting mechanism and stress polygon approach, measurement of the minimum horizontal stress (Shmin) from minifrac tests and observations of the compressive failures from the acoustic image log provide strong constraints on the SHmax magnitude in the reservoir interval in the absence of core-measured rock strength. Interpreted breakout widths exhibit a range between 32.6° and 90.81°, which indicates a SHmax range of 24.4–34.7 MPa/km. The average breakout width of 62.58° translates to a narrower SHmax gradient range, varying between 27.2 and 31.2 MPa/km. The relative magnitudes of the principal stresses indicate a strong strike-slip tectonic stress state. Considering all the uncertainties, we infer a SHmax/Shmin ratio of 1.41–1.81 within the Ordovician interval.

Parameter identification of minifrac numerical tests using a gradient boosting‐based proxy model and genetic algorithm

AbstractIn recent years, the petroleum industry has devoted considerable attention to studying fluid flow inside fracture channels due to the discovery of naturally fractured reservoirs. The behavior prediction of these reservoirs is a well‐known challenging task, in which the initial stage consists of identifying reservoir hydromechanical parameters. This work proposes an artificial intelligence‐based approach to identify hydromechanical parameters from borehole injection pressure curves acquired through minifrac tests. This approach combines proxy modeling with a stochastic optimization algorithm to match observed and predicted borehole pressure curves. Therefore, a gradient boosting‐based proxy model is built to predict borehole pressure curves, considering a proper strategy to develop time series modeling. Moreover, a Bayesian optimization algorithm is applied to compute the gradient boosting hyperparameters. In this optimization scenario, this paper proposes an appropriate objective function established from the assumed time series prediction strategy and the k‐fold cross‐validation. Finally, a genetic algorithm is adopted to identify unknown hydromechanical parameters, solving an inverse problem. Based on the proposed workflow, a study of the importance of the hydromechanical parameters is developed. To assess the methodology applicability, the approach is employed to identify parameters in synthetic and field minifrac tests. The results present how this approach can adequately identify hydromechanical parameters of hydraulic fracturing problems.

Using One-Dimensional Geomechanical Model for Determining the Safe Wellbore Orientation of Zubair Reservoir, Southern Iraq

The wellbore instability issues are firmly occurring in the Iraqi oilfield and particularly in the southern region of Iraq. It is causing a significant loss of time dealing with many types of downhole problems, as well as an increase in the operations costs because of the instability consequences. By using the well information and open-hole logging data, the One-Dimensional (1-D) geomechanical model generated with Schlumberger Techlog software (V.2015) was used to assess the mechanical stability of the wellbore. The model was calibrated and validated by using core data (Triaxial test), the formation pore pressures, and the Mini-frac test). The 1-D model was validated across the actual well conditions (i.e., the original mud weight and the actual wellbore failure) by using three criteria of failures which are Modified Lade, Mogi-Coulomb, and Mohr-Coulomb. The validation process showed that the failure criterion of Mogi-Coulomb is better than the other two criteria in presenting the actual borehole failure, and thus it can be used to develop the plans of wellbore orientation. By investigating wellbore orientation with various scenarios, ranging from a vertical trajectory to the horizontal strategy, the wellbore orientation is mainly safe (with the minimum breakout) in vertical and inclined wells up to 40º with minimum mud weight of 11.7 and 12.6 ppg. The optimum wellbore trajectory should be in the direction of minimum horizontal stress, which is North-West to South-East (130º-160º). The developed plans provide a guideline for performing stable drilling operations in the south of Iraq and the nearby areas, thus effectively contributing in reduction the overall cost.

Engineers and Execs Agree Shale Science Projects Are Worth It

_ It was a testimony to the impact science projects have had on the shale sector that kicked off the 15th Annual SPE Hydraulic Fracturing Technology Conference and Exhibition (HFTC) held in the Houston area. When the technical experts and executives gathered, they discussed how, after years of subsurface study, past beliefs have been dispelled and new learnings translated into multimillion- to billion-dollar business decisions. At the conference’s plenary session, attendees learned from Devon Energy about why the oil company has become a vocal champion of refracturing and the influence it had on a recent acquisition that doubled its position in the Eagle Ford Shale. Bakken Shale producer Hess Corp. tied more than a decade of work to its experimental wells that use fractures from other wells to produce oil, as well as its commitment to developing automated fracturing despite facing obstacles in industry collaboration. SM Energy also showcased a double minifrac test as an example of the new experiments guiding its unconventional strategy in the Eagle Ford and Austin Chalk formations found in south Texas. A closer look at what they had to say is here. Betting Big on Refracturing In SPE 212340, Devon offered fresh details on its big refracturing study in the Eagle Ford Shale—one that played into its decision to spend $1.8 billion last year on an acquisition in the south Texas play. It involved two parent wells originally stimulated in 2013 and then refractured in January 2022. As a result, Devon reports the respective estimated ultimate recovery (EUR) from each well soared by 27% and 46%. These are wells that had been producing about 20 to 25 B/D, and according to data shared in the paper, at least one of them topped 1,000 B/D in the weeks following the refracturing. Kourtney Brinkley described the recovery boost as a “significant step change” that helped the company realize a “need to incorporate recompletions into our development plans as we go forward.” The drilling and completions engineer who helped lead the project for Devon reported that the operator’s wider refrac program in the play has seen incremental EUR increases as high as 75% with the average being at around 50%. The figures translate to a rate of return between 97 to 220%, which she said makes them “very economic projects.” The project Brinkley outlined at the conference fell under the US Department of Energy’s (DOE) hydraulic fracturing test site program. With the help of federal funding, Devon was able to deploy an enviable array of diagnostic tools. An observation lateral was drilled to monitor refracturing along with new completions on the pad. About 420 ft of core was taken from the observation well to capture some of the pad’s parent well fracture system. The diagnostic kit included multiple fiber-optic installations, sealed wellbore pressure monitoring, downhole pressure gauges, ultrasonic imaging, and more. With this rare suite of technologies, Devon was able to learn exactly how poor the initial parent completions were while later seeing just how effective its refrac designs ended up being. First came the parent core-through that showed while a hydraulic fracture was present every 10 ft on average, the number of propped fractures represented just 8% of the total found. Ultrasonic imaging aligned, showing initial completion design netted a cluster efficiency rate of just 19%. Post-refrac, that number was increased to over 80%, which implies to Devon that there are a good degree more propped fractures today.

In situ stress field in the Athabasca oil sands deposits: Field measurement, stress-field modeling, and engineering implications

In situ stress is one of the key engineering parameters that ensures caprock integrity in steam-assisted gravity drainage (SAGD) operations. Massive steam injections during an SAGD operation leads to significant changes in the pore pressure, temperature, stress, and volumetric strain in the rock formations. These changes trigger deformation and stress redistribution in the overburdened strata, which could lead to a containment breach of the caprock through shear or tensile failure. To ensure subsurface steam containment, both to satisfy public safety considerations and instill confidence that the steam containment will continue over the necessary timescales, the Alberta government requires every SAGD operator to measure the in situ stress conditions in the oil sands reservoir and its caprock. Minifrac test is a suggested method that can measure the minimum principal stress with high confidence. A safety factor (SF) of 80% is used to determine the maximum operation pressure (MOP) for safe SAGD operations; in other words, MOP = 80%*σmin, where σmin is the minimum principal stress at the base of the caprock. In most cases, this 80% SF safeguards the SAGD injection pressure to always remain lower than the σmin at the base of the caprock, ensuring that no tensile fractures are initiated at the caprock.In this study, we compiled a database containing in excess of 100 minifrac datasets across the Athabasca oil sands region and constructed an in situ stress map. Based on our in situ stress dataset, we developed a quantitative risk model to analyze the effects of uncertainties on the probability of exceedance (i.e., the probability that the MOP exceeds the fracture pressure at the base of the caprock). The risk model involves defining probability distributions to quantify the uncertainties at the shallowest depth and minimum stress gradient. The output of the risk model was a set of predictions of exceedance probabilities, which were computed using Monte Carlo simulations. Through a statistical analysis of this in situ database and risk-based simulation analysis, this study demonstrates the reliability of a SF of 80%.

Port-Opening Falloff Test: A Complementary Test to Diagnostic Fracture Injection Test

Summary Conventional fracture injection/falloff tests, such as minifrac or diagnostic fracture injection test (DFIT), are commonly used to characterize shale and tight reservoirs. For ultralow-permeability reservoirs, a reliable DFIT requires a long falloff period after a short injection period. A long falloff observation period of weeks or months is often not economically viable. In addition, the recent economic downturn requires operators to seek cost-effective alternatives to further optimize expenditures. An alternative to a DFIT is a port-opening falloff test (POFOT). Many horizontal completions use a pressure-activated sleeve in the toe of the well to provide formation access after the casing integrity test. Most sleeves open at a pressure in excess of the formation breakdown pressure, after which the wellbore pressure declines toward reservoir pressure. This study first introduces the concept of the POFOT as a novel physical test. A new test method must demonstrate that it accesses the formation of interest and that the data obtained are applicable. A workflow is developed to demonstrate this and is applied to falloff data from POFOTs conducted in five horizontal wells completed in five formations. The results show that the fluid leaving the port is highly likely to break down both the cement sheath and the matrix and create a fracture which then closes. Observation of the well pressure after port opening resembles that from a DFIT. However, without a fixed-duration and constant-rate injection period, there is no accepted method to apply. Nevertheless, both qualitative and quantitative analyses of the falloff data provide a good estimation of reservoir pressure with a reasonable approximation of fracture closure when compared with the estimates from DFIT analysis from offset wells. The key challenges in parameter estimation, besides the development of an appropriate analysis method, are short falloff data and noisy early-time data due to wellbore resonance (WBR), low-resolution gauges, and change in sampling frequency.

Estimating the Least Principal Stress in a Granitic Rock Mass: Systematic Mini-Frac Tests and Elaborated Pressure Transient Analysis.

The hydraulic fracturing technique (also termed mini-frac test) is commonly used to estimate the in situ stress field. We recently conducted a mini-frac stress measurement campaign in the newly-established Bedretto Underground Laboratory (BedrettoLab) in the Swiss Alps. Four vertical boreholes, dedicated for stress characterization of the granitic rock mass, hosted a total of 19 mini-frac test intervals. Systematic pressure transient analysis was performed to carefully estimate the magnitude of the least principal stress (S_mathrm {3}). We compared five different methods (inflection point, bilinear pressure decay rate, tangent, fracture compliance, and jacking pressure) to identify an adequate approach best suited for our test scale and the host rock mass. We found that the methods used to determine the fracture closure pressure underestimate the magnitude of S_mathrm {3}, presumably due to the rapid closure of the hydraulic fracture after shut-in. The most consistent results were found using the inflection point and bilinear pressure decay rate method, which both determine the (instantaneous) shut-in pressure as the proxy for the S_mathrm {3} magnitude. The determined shut-in pressure, or S_mathrm {3} magnitude, is 14.6pm 1.4 MPa from the inflection point method. This allowed us to further estimate the stress environment around the BedrettoLab, which is transitional between normal and strike-slip faulting. The measured local pore pressures from extended shut-in periods are between 2.0 and 5.6 MPa, significantly below hydrostatic. A combination of drainage, cooling, and the excavation damage zone of the tunnel may have significantly perturbed the in situ stress field in the vicinity of the BedrettoLab.

Determination of Safe Mud Weight Window in Rumaila Oilfield, Southern Iraq

The oil and gas industry, wellbore instability plays an important role in financial losses and stops the operations while the drilling which leads to extra time known as non-productive time. In this work, a comprehensive study was carried out to realize the nature of the instability problems of the wellbore in Rumaila oilfield to improve the well design. The study goal is to develop a geomechanical model in one dimension by utilizing Schlumberger Techlog (Version 2015) software. Open hole wireline measurements were needed to develop the model. The model calibrating and validating with core laboratory tests (triaxial test), well test (Mini-frac test), repeated formation test. Mohr-Coulomb, Mogi-Coulomb, and Modified Lade are the three failure criteria which utilized to analyze the borehole breakouts and to determine the minimum mud weight needed for a stable wellbore wall. For more accuracy of the geomechanical model, the predicted profile of the borehole instability is compared with the actual failure of the borehole that is recorded by caliper log. The results of the analysis showed that the Mogi-Coulomb criteria are closer to the true well failure compared with the other two criteria and considered as the better criteria in predicting the rock failure in the Rumaila oilfield. The wellbore instability analysis revealed that the vertical and low deviated wells (less than 40º) is safer and more stable. While, the horizontal and directional wells should be drilled longitudinally to the direction of the minimum horizontal stresses at a range between 140º–150º North West-South East and the mud weight recommended is increased to 10.5 ppg to avoid most of instabilities problems. The results contribute in development plan of the wells nearby the studied area and decreasing NPT and cost.

Present-day stress field and stress path behaviour of the depleted Mishrif reservoir from the super-giant Zubair oilfield, Iraq – A geomechanical case study

Accurate understanding of the reservoir pore pressure and in-situ stress behaviour in response to depletion has critical effects in production optimization and field redevelopment while ensuring reservoir integrity. This work presents the first reservoir geomechanical modeling from the supergiant Zubair oil field, southern Iraq to decipher the pore pressure, in-situ stresses and depletion stress path of the middle Cretaceous Mishrif limestone reservoir. Vertical stress (Sv) has 0.97–0.99 psi/ft gradient. Minimum horizontal stress (Sh) estimated from effective stress ratio and Poisson's ratio-based approaches yielded an about 0.58–0.76 psi/ft gradient and validated with C-category fracture closure pressure data available from mini-frac tests. In absence of image log-based breakout widths, maximum horizontal stress (SH) is estimated from three approaches, which provided a gradient range of 0.89–1.21 psi/feet. Relative stress magnitudes (SH ≥ Sv >Sh) indicate a normal to strike-slip faulting transitional tectonic state in the study area. C-quality wellbore breakouts, interpreted from the oriented four arm caliper data infer a mean N60°E SH orientation, which is parallel to the movement direction of the Arabian plate towards the Eurasian plate. Recent downhole measurements indicate that the primary producer Mishrif limestone is in depleted condition. Stress path, interpreted from the reduction of pore pressure (Δpp) and minimum horizontal stress (ΔSh), yields average values of 0.65 and 0.62 for upper and lower Mishrif, respectively. Deformation analysis in reservoir space indicates stress path in depleted Mishrif formation of Zubair oil field is less than the normal faulting limit (0.71) and depletion-induced faulting is therefore unlikely to occur.

Stress analysis using direct-S wavelets produced by a vertical vibrator

We have determined how to extract the azimuth of maximum horizontal stress (SHmax) in deep rocks by doing a simple 360° mathematical rotation of a downgoing direct-S wavelet generated at the baseplate of a surface-based vertical vibrator. We worked with direct-S wavelets that travel through stressed rocks to a deep horizontal vertical seismic profile (VSP) geophone. We find that the azimuth where a polarity reversal occurs in mathematical rotations of this downgoing direct-S wavelet defines the azimuth of the SHmax in the overlying rocks. We tested this direct-S wavelet rotation method for determining the SHmax azimuth at a site in the Illinois Basin using legacy VSP data acquired in 2013. SHmax azimuths indicated by this simple wavelet-rotation method were determined when vertical vibrators were stationed at zero offset, at far offset, and at different azimuths around a VSP receiver well. These VSP-based SHmax azimuths agreed with the azimuth of the SHmax found by traditional minifrac tests in the VSP receiver well. This simple VSP data analysis procedure for detecting the azimuth of maximum horizontal stress has never, to our knowledge, been reported or discussed in the geophysical literature. This technical finding should be of interest to the worldwide geophysical community, especially to people who need to monitor how stress fields shift when fluids are injected into, or extracted from, deep porous reservoirs.

In Situ Stress Prediction in Subsurface Rocks: An Overview and a New Method

Methods for determining in situ stresses are reviewed, and a new approach is proposed for a better prediction of the in situ stresses. For theoretically calculating horizontal stresses, horizontal strains are needed; however, these strains are very difficult to be obtained. Alternative methods are presented in this paper to allow an easier way for determining horizontal stresses. The uniaxial strain method is oversimplified for the minimum horizontal stress determination; however, it is the lower bound minimum horizontal stress. Based on this concept, a modified stress polygon method is proposed to obtain the minimum and maximum horizontal stresses. This new stress polygon is easier to implement and is more accurate to determine in situ stresses by narrowing the area of the conventional stress polygon when drilling-induced tensile fracture and wellbore breakout data are available. Using the generalized Hooke’s law and coupling pore pressure and in situ stresses, a new method for estimating the maximum horizontal stress is proposed. Combined it to the stress polygon method, a reliable in situ stress estimation can be obtained. The field measurement method, such as minifrac test, is also analyzed in different stress regimes to determine horizontal stress magnitudes and calibrate the proposed theoretical method. The proposed workflow combined theoretical methods to field measurements provides an integrated approach for horizontal stress estimation.

Tunnel Hydraulic Fracturing evaluation and comparing with conventional hydraulic fracturing computation

Tunnel Hydraulic Fracturing is one method of well fracturing operation which generates tunnel in proppant filled fractured rock, near wellbore. The tunnels are in-between packs of proppant. The occurrence of tunnel is caused by certain pumping technique during hydraulic fracturing operation. Frac fluid is pumped continuously, along with proppant is pumped intermittently. These tunnels generate high conductivity media in the fracturing geometry. The subject well was initially flow tested intermittently with 95% to 100% oil cut. The permeability from log correlations is 8 mD, with 1824 Psireservoir pressure, from surrounding wells. Rock mechanic and type of stresses were evaluated to determine tunnel fracturing candidacy. After designing Tunnel Fracturing Design, operationally Pre-fracturing test sequences was executed, which is followed by re-design and operation of Mini frac test. The final design is followed by performing pulsed Mainfrac. The Tunnel Fracturing geometry was computed by service provider software, and the Productivity Index PI by spreadsheet. The Conventional Fracturing and its PI was computed by using spreadsheet. The Tunnel Hydraulic FracturingPI was as much as 4.22 while Conventional Fracturing was 2.05.

Field experience and numerical investigations of minifrac tests with flowback in low-permeability formations

In this study, flowback-assisted minifrac tests were conducted in low-permeability shale and salt formations to measure the in situ stress. An injection/flowback testing protocol was implemented in each test to achieve accuracy and efficiency. Accurate and efficient injection/flowback testing is very important, given the impermeable nature of these formations and the need to complete each test as quickly as possible. Each flowback cycle yields a distinct and repeatable fracture closure signature, simplifying the interpretation of the fracture closure pressure. The objective of this paper is to share our field experience and to present a numerical analysis of the flowback test pressure responses, fracture closure behaviors, and fracture closure diagnostic methods. Examples from open-hole and cased-hole minifrac tests are used to demonstrate site operation procedures. Then, two numerical models are presented for simulating the fracture closure behavior during a flowback test. Field evidence is provided to demonstrate that the fracture closure pressures from the flowback tests are identical to those from tests without flowback. The fracture closure diagnostic methods for flowback tests are discussed, and it is found that the G-function diagnostic method yields a distinct fracture closure signal during the flowback tests. This study is intended to provide additional insights regarding flowback tests by sharing our successes, experience, and knowledge, thereby benefiting the industry.

Geomechanical Analysis for Deep Shale Gas Exploration Wells in the NDNR Blocks, Sichuan Basin, Southwest China

The abundant reserve of shale gas in Sichuan Basin has become a significant natural gas component in China. To achieve efficient development of shale gas, it is necessary to analyze the stress state, pore pressure, and reservoir mechanical properties such that an accurate geomechanical model can be established. In this paper, Six wells of Neijiang-Dazu and North Rongchang (NDNR) Block were thoroughly investigated to establish the geomechanical model for the study area. The well log analysis was performed to derive the in-situ stresses and pore pressure while the stress polygon was applied to constrain the value of the maximum horizontal principal stress. Image and caliper data, mini-frac test and laboratory rock mechanics test results were used to calibrate the geomechanical model. The model was further validated by comparing the model prediction against the actual wellbore failure observed in the field. It was found that it is associated with the strike-slip (SS) stress regime; the orientation of SHmax was inferred to be 106–130° N. The pore pressure appears to be approximately hydrostatic from the surface to 1000 m true vertical depth (TVD), but then becomes over-pressured from the Xujiahe formation. The geomechanical model can provide guidance for the subsequent drilling and completion in this area and be used to effectively avoid complex drilling events such as collapse, kick, and lost circulation (mud losses) along the entire well. Also, the in-situ stress and pore pressure database can be used to analyze wellbore stability issues as well as help design hydraulic fracturing operations.

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

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

Overburden characterization with formation pore pressure and anisotropic stress field estimation in the Athabasca Basin, Canada

One of the challenges encountered during the life cycle of an oil-sand thermal-production reservoir is the prediction of the formation pore pressure and in situ stress regime during the assessment phase of the reservoir development and, more importantly, during the development phase. We have investigated the state of formation pore pressure and stress in the overburden — represented by the Clearwater Formation, Grand Rapids Formation, and Colorado Group — of a preproduction oil-sands reservoir situated in the Athabasca Basin of Alberta, Canada. Our methodology integrates pressure data from piezometers, stress data from mini-frac (MF), dipole sonic logs, and elastic properties obtained from multicomponent 3D seismic inversion data. It combines the Terzaghi effective stresses with the Schoenberg and Sayers elastic stiffness matrix for horizontal transversely isotropic fractured materials. The total principal stresses (vertical, minimum, and maximum horizontal stresses) are expressed as functions of the normal fracture weakness (anisotropic correction factor), formation pore pressure, seismic data (Lamé constants), and the Biot-Willis coefficient. The effective principal stresses are estimated from the equivalent total principal stresses and the formation pore pressure multiplied by the Biot-Willis coefficient. On all three overburden intervals analysed, the relations between principal stresses indicate a normal stress regime. The estimated total minimum horizontal stress matches the MF values within 10%. The formation pore pressure, along with the 3D seismically derived estimates of the total and effective principal stresses, allows for better assessment of the caprock integrity and for operational savings based on a reduced number of MF tests. It can also be used for stress estimation within the formations hosting aquifers, which is so important for thermal production. Understanding the subsurface on the reservoir area is important for efficient production, but knowing the subsurface of the overburden is equally important for reducing potential issues due to production.

Stress field and active faults in the orogenic front of the Andes in the Malargüe fold-and-thrust belt (35°–36°S)

We integrate field and wellbore data to discuss the stress field in the frontal sector of the Malargüe fold-and-thrust belt (Andes of Argentina). Surface observations indicate N-S thrusts and NW to WNW and ESE strike-slip faults are active in the study area. Inversion of fault kinematic indicators, combined with borehole breakout data and a mini-frac test within the study area, constrain the Quaternary to recent stress state, which is characterized by a subhorizontal, E-W oriented maximum stress, and by intermediate and minimum stresses with similar magnitudes that are locally interchanged, producing a setting in which reverse and strike-slip faults are alternatively active. The implications of the recognized structures for earthquake hazard are examined.

Determine In-Situ Stress and Characterize Complex Fractures in Naturally Fractured Reservoirs from Diagnostic Fracture Injection Tests

Estimation of in-situ stresses has significant applications in earth sciences and subsurface engineering, such as fault zone studies, underground CO2 sequestration, nuclear waste repositories, oil and gas reservoir development, and geothermal energy exploitation. Over the past few decades, Diagnostic Fracture Injection Tests (DFIT), which have also been referred to as Injection-Falloff Tests, Fracture Calibration Tests, and Mini-Frac Tests, have evolved into a commonly used and reliable technique to obtain in-situ stress. Simplifying assumptions used in traditional methods often lead to inaccurate estimation of the in-situ stress, even for a planar fracture geometry. When a DFIT is conducted in naturally fractured reservoirs, the stimulated natural fractures can either alter the effective reservoir permeability within the distance of investigation or interact with the hydraulic fracture to form a complex fracture geometry, this further complicates stress estimation. In this study, we present a new pressure transient model for DFIT analysis in naturally fractured reservoirs. By analyzing synthetic, laboratory and field cases, we found that fracture complexity and permeability evolution can be detected from DFIT data. Most importantly, it is shown that using established methods to pick minimum in-situ stress often lead to over or underestimates, regardless of whether the reservoir is heavily fractured or sparsely fractured. Our proposed “variable compliance method” gives a much more accurate and reliable estimation of in-situ stress in both homogenous and naturally fractured reservoirs. By combining the unique pressure signatures associated with the closure of natural fractures, a lower bound on the horizontal stress anisotropy can be estimated.

OPTIMISATION OF HYDRAULIC FRACTURING DESIGN IN LOWER OLIGOCENE RESERVOIR, KINH NGU TRANG OILFIELD

Kinh Ngu Trang oilfield is of the block 09-2/09 offshore Vietnam, which is located in the Cuu Long basin, the distance from that field to Port of Vung Tau is around 140 km and it is about 14 km from the north of Rang Dong oilfield of the block 15.2, and around 50 km from the east of White Tiger in the block 09.1. That block accounts for total area of 992 km2 with the average water depth of around 50 m to 70 m. The characteristic of Oligocene E reservoir is tight oil in sandstone, very complicated with complex structure. Therefore, the big challenges in this reservoir are the low permeability and the low porosity of around 0.2 md to less than 1 md and 1% to less than 13%, respectively, leading to very low fracture conductivity among the fractures. Through the Minifrac test for reservoir with reservoir depth from 3,501 mMD to 3,525 mMD, the total leak-off coefficient and fracture closure pressure were determined as 0.005 ft/min0.5 and 9,100 psi, respectively. To create new fracture dimensions, hydraulic fracturing stimulation has been used to stimulate this reservoir, including proppant selection and fluid selection, pump power requirement. In this article, the authors present optimisation of hydraulic fracturing design using unified fracture design, the results show that optimum fracture dimensions include fracture half-length, fracture width and fracture height of 216 m, 0.34 inches and 31 m, respectively when using proppant mass of 150,000 lbs of 20/40 ISP Carbolite Ceramic proppant.