Fracture Stimulation Treatments Research Articles

Analysis of Production Data from Communicating Multifractured Horizontal Wells Using the Dynamic Drainage Area Concept

Summary Reduction of fracture/well spacing and increases in hydraulic fracture stimulation treatment size are popular strategies for improving hydrocarbon recovery from multifractured horizontal wells (MFHWs). However, these strategies can also increase the chance of fracture interference, which can not only negatively impact the overall production but also introduce complexities for production data analysis. A semianalytical model is therefore developed to analyze production data from two communicating MFHWs and applied to a field case. The new semianalytical model uses the dynamic drainage area (DDA) concept and assumes three porosity regions. The three-region model is comprised of a primary hydraulic fracture (PHF), an enhanced fractured region (EFR) adjacent to the PHF, and a nonstimulated region (NSR). Assuming a well pair primarily communicates through PHFs, the equations for two communicating wells are coupled and solved simultaneously to model the fluid transfer between the wells. This method is used within a history-matching framework to estimate the communication between the wells by matching the production data. The semianalytical model is first verified against a more rigorous, fully numerical simulation model for a range of fracture/reservoir properties. These comparisons demonstrate that there is excellent agreement between the fully numerical simulation model results and the new semianalytical model. The semianalytical model is then employed to history-match production data from six MFHWs (drilled from two adjacent well pads) exhibiting different degrees of communication. For the purpose of history matching the data, only strong communication between pairs of wells (intrapair communication) is considered in the three-region model, and the results show good agreement with the field data. A flexible, yet simple, semianalytical model is developed for the first time that can accurately model the communication between multiple well pairs. This approach can be used by reservoir engineers to analyze the production data from communicating MFHWs.

A semi-analytical model for estimation of hydraulic fracture height growth calibrated with field data

The vertical growth of hydraulic fractures in layered formations has been a topic of interest amongst researchers because of its critical influence on well performance. The analytical solution to the fracture vertical growth in layered formations is primarily based on force balance amongst various formation layers of segments that the vertical fracture intersects. The pressure associated with fluid movement in the vertical direction in a hydraulic fracture is generally ignored in most semi-analytical solutions to height-growth problems, especially if the vertical growth occurs at a slow pace. For a slow advancing vertical fracture, the tips are assumed to be near stationary, and the assumption is termed as equilibrium-height model. The model was first conceptualized for a simple 3-layered problem and later extended to multi-layered applications. The available literature shows model-derived solution for simple cases but lack in-depth study of real-world examples, which in doing so could highlight some of the model limitations.The semi-analytical model presented in the study, was first benchmarked by replicating the data published in the existing literature, and then applied to the field cases to compare its output with the observed data. Unlike the typical approach taken in the literature where the location of one of the tips of the fracture is assigned and the position of other tip is determined, the current model determines the most suitable position for a fracture of given height and stress profile. Additionally, new features were added to the model when evaluating the field cases. These include, incorporating calculation procedures that provide accurate fracture placement for given conditions, handling layered property inputs up to 100 layers, and the ability to include variable fracture pressure as opposed to a constant pressure approach.The model was applied on several cases from the field, four of which are presented here. The analysis showed that there is a close agreement between the predicted and the observed fracture heights. The hybrid feature of the model with inclusion of non-uniform pressure drop profile in the fracture, also helped in calibrating a case where a mismatch was observed. It was concluded that this model can predict fracture height growth with reasonable accuracy for cases with low injection rates where low viscosity fluid is used and requires calibration in cases where high net pressures are expected.The newly developed model is simple to program and can assist in making quick estimates of fracture vertical growth in vertical wells with low-rate fracture stimulation treatments.

A Semianalytical Modeling Approach for Hydraulic Fracture Initiation and Orientation from Perforated Wells

Summary Accurate prediction of fracture initiation pressure and orientation is paramount to the design of a hydraulic fracture stimulation treatment and is a major factor in the treatment's eventual success. In this study, closed-form analytical approximations of the fracturing stresses are used to develop orientation criteria for relative-to-the-wellbore (longitudinal or transverse) fracture initiation from perforated wells. These criteria were assessed numerically and found to overestimate the occurrence of transverse fracture initiation, which only takes place under a narrow range of conditions in which the tensile strength of the rock formation is lower than a critical value, and the breakdown pressure falls within a “window.” For a case study performed on the Barnett Shale, transverse fracture initiation is shown to take place for breakdown pressures below 4,762 psi, provided that the formation's tensile strength is below 2,482 psi. A robust 3D finite volume numerical model is used to evaluate solutions for the longitudinal and transverse fracturing stresses for a variable wellbore pressure, hence developing correction factors for the existing closed-form approximations. Geomechanical inputs from the Barnett Shale are considered for a horizontal well aligned parallel to the direction of the least compressive horizontal principal stress. The corrected numerically derived expressions can predict initiation pressures for a specific orientation of fracture initiation. Similarly, at known breakdown pressures, the corrected expressions are used to predict the orientation of fracture initiation. Besides wellbore trajectory, the results depend on the perforation direction. For the Barnett Shale case study, which is under a normal faulting stress regime, the perforations on the side of the borehole yield a wider breakdown pressure window by 71% and higher critical tensile strength by 32.5%, compared to perforations on top of the borehole, implying better promotion of transverse fracture initiation. Leakage of fracturing fluid around the wellbore, between the cemented casing and the surrounding rock, reduces the breakdown pressure window by 11% and the critical tensile strength by 65%. Dimensionless plots are employed to present the range of in-situ stress states in which longitudinal or transverse hydraulic fracture initiation is promoted. This is useful for completion engineers; when targeting low permeability formations such as shale reservoirs, multiple transverse fractures must be induced from the horizontal wells, as opposed to longitudinal fracture initiation, which is desired in higher permeability reservoirs or “frac-and-pack” operations.

Advancing Production Flow Profiling With Subatomic Fingerprints and Big Data Analytics

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196172, “Unleashing the Power of Smart Particles for Completion Diagnostics: Advancing the Production-Flow-Profiling Technology With Subatomic Fingerprints and Big-Data Analytics,” by Talgat Shokanov, SPE, and Pavel Khudorozhkov, QuantumPro, and Adilkhan K. Shokanov, Abai University, prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 30 September-2 October. The paper has not been peer reviewed. This paper describes a smart-tracer-portfolio testing and design solution for multistage hydraulic fracturing which will, write the authors, enable operators to reduce operating cost significantly and optimize production in shale wells. The technology combines recently developed smart tracers with advanced subatomic measurements in an automated process with stringent quality control that assures precise tracer addition onsite and provides accurate and actionable completion diagnostics results at a fraction of the cost of production-logging testing, distributed temperature testing, or distributed acoustic sensing. Introduction Multistage hydraulic fracturing operations costs - including high-pressure pumping, proppant, and fluid - ranged from $2.9 million to $5.6 million per well in a typical US shale well in 2018, representing close to 60% of the total drilling and completion cost for each well. Yet industry studies reported that up to 50% of the clusters and stages and up to 40% of the fracture net-works do not produce in the current geometric factory-mode-completion approach, leading to estimates that up to 40% of the drilled and completed shale wells in North America alone could be uneconomical. Additionally, interactions between fractures in adjacent horizontal wells, and the costly negative effects of these interactions, have become the focus of much discussion and debate within the technical community. The impetus for this attention has been the effect of these interactions on productivity and the mechanical integrity of the parent wells. These issues drive the need for oil and gas operators to have more-accurate, affordable, and timely data on the performance of individual fracturing stages, measured intrawell communication, and temporary and long-term frac/frac connections to enable improved decision-making and optimization of multistage hydraulic fracturing operations as well as overall field development. The complete paper describes smart tracer technology, including a patented portfolio and fracturing-/completion-optimization work flow; laboratory testing and performance analysis; and integration with completion diagnostics. Smart Tracer Technology To control the effectiveness of multistage hydraulic fracturing stimulation treatments, it is essential to use special tracing methods based on the addition of the labeled substance to the proppant, water, or gas, and monitor the release of tracers with flowback water and produced oil and gas from the current well or nearby observation wells. Currently, conventional water- and oil-soluble chemical substances with fluorescent properties and ionic, organic materials, or radioactive isotopes, are used as the tracers. Tracers with fluorescent properties and ionic and organic materials are high-cost, limited to chemical-measurement techniques at a molecular level, and often have reported false-positive results for long-term communication. Environmental regulations in many countries prohibit the use of radioactive tracers (i.e., radioactive isotopes) because they pollute the environment and could contaminate subsurface layers.

Analysis of Remote Displacement Patterns Monitored by Tiltmeters During Fluid Injection Into Reservoirs

In order to take far-field translational tilts into account during studying reservoir flow process of CO2 injection, a group of tiltmeters were installed as array covering estimate range of ground spreading from the injection well. The measurements were applicable to ground deformations during a fracturing stimulation treatment, a short-term test of CO2 injection into relatively shallow coal seams and a CO2 injection into deep saline aquifer. An attempt to quantitatively model the rational association between reservoir volumetric disturbance underground and its induced corresponding rather slight distortion on surface was presented. It is as well demonstrated how to sufficiently manipulate vertical unstructured and horizontal divergent model numerical discretization, which eventually makes it feasible to study mechanism between reservoir flow and reservoir Geomechanics by full-field reservoir model. The potential algorithms to improve the computational efficiency and an actual demand for an ambitious solver to inverse coupling problem are finally discussed. The study proposed the development of high-efficiency software package fully capable of dealing with reservoir flow and reservoir Geomechanics so as to implement the history match study not only on a reservoir itself being injected but also including the full field deformation performance up to the costly ground displacement monitoring data.

A 3D numerical model for investigation of hydraulic fracture configuration in multilayered tight sandstone gas reservoirs

Multilayered tight sandstone gas reservoirs with low porosity and low permeability are usually developed by two kinds of hydraulic fracturing techniques, including general fracturing (simultaneously fracturing multiple target zones) and separate layer fracturing (sequentially fracturing the target zones from the bottom-up). However, fractures from different target zones are likely to communicate in the fracturing process which detrimentally causes the waste of fracturing fluid and proppants and finally affects the efficiency of fracturing treatment. Therefore, investigation related to hydraulic fracture configurations under different fracturing stimulation treatments is necessary with the objective of optimizing the fracturing design and predicting the production rate. In this paper, a 3D finite element model is established to simulate the propagation of multiple hydraulic fractures in the vertical well, and fracture configurations under different fracturing techniques and formation properties are analyzed and compared. The results indicate that, in vertical wells, stress interference between the fracture tips will accelerate the communication of adjacent vertical fractures along the height direction. And separate layer fracturing is preferable for stimulating multilayered tight sandstone gas reservoirs. Also, adjacent pay zones and barriers with high in situ stress contrast, high tensile strength contrast and low elastic modulus contrast are able to effectively prevent the communication of fractures along the height direction and lead to the increase of fracture length and width, and so does the barriers with large thickness.

An integrated study on the sensitivity and uncertainty associated with the evaluation of stimulated reservoir volume (SRV)

Economic production from ultra-tight shale formations depends greatly on the effectiveness of the hydraulic fracturing stimulation treatment. As a critical monitoring technology for unconventional reservoir development, microseismic plays an important role in fracture location analysis and evaluation of the fracturing treatment. For microseismic analysis, particularly for fracture inversion, uncertainties are common and are associated with the collected microseismic data themselves and formation properties such as velocity analysis result. Therefore, large differences are often observed between the fitted stimulated reservoir volume (SRV) from microseismic events and the volume obtained through hydraulic fracture modeling.This paper combines the microseismic monitoring, hydraulic fracturing simulation and SRV fitting techniques to investigate the inter-relationship of data uncertainties and to provide a possible methodology for guiding the stimulation treatment during reservoir development. The hydraulic fracturing process is simulated to obtain a realistic set of microseismic events that are generated from hydraulic fracture propagation and the pore pressure increase in the matrix. In order to examine the impacts of the uncertainties on the estimated locations of the microseismic events, different levels of noise are added to the first arrival times during the inversion process. Because the microseismic event locations inverted from the first arrival times with noise are very scattered, a denoising procedure based on probability theory is applied to identify and exclude the outliers in the MS event clouds. The discrete bin, 3D Delaunay triangulation and ellipsoid fitting methods are used to compute SRV from the inverted microseismic events with noise. Comparisons are made to examine the sensitivities of the different SRV fitting methods with respect to data noise. The results show that the two discrete bin algorithms are relatively stable, while the MVEE and 3D Delaunay triangulation algorithms are not very robust and can be easily affected by the noise in the observed data.

One-Trip Multizone Sand-Control-Completion System in the Gulf of Mexico Lower Tertiary

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27183, “Current State of the One-Trip Multizone Sand-Control-Completion System and the Conundrum Faced in the Gulf of Mexico Lower Tertiary,” by Bruce Techentien, Tommy Grigsby, and Thomas Frosell, Halliburton, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission. This paper provides perspective on the current state of multizone completion technology and issues encountered in the industry with developing a system that offers increased capabilities to meet the increasing challenges presented by the Lower Tertiary in the Gulf of Mexico (GOM). The multizone technology has proved to be an enabler for cost-efficient completions in the shallow-well environment and in the high-cost ultradeepwater environment requiring high-rate fracture-stimulation treatments. Lower Tertiary GOM The Lower Tertiary play is south and west of the Miocene area in the GOM and is, consequently, in deeper water. The Lower Tertiary is located approximately 175 miles offshore and is estimated at 80 miles wide and up to 300 miles long. Water depths are from 5,000 to 10,000 ft. Production targets are at depths of 10,000 to 30,000 ft subsea. The Tertiary trend is from 66 million to 38 million years old. Within the Lower Tertiary, the Lower Wilcox portion presents sheet to amalgamated-sheet sands considered to be part of a regional basin floor fan system. The Late Paleocene to Early Eocene (Wilcox equivalent) reservoirs are considered to be laterally extensive sheet sands that were deposited in deep water. These reservoirs are distributed across an area largely covered by the allochthonous Sigsbee salt canopy. It is this canopy that causes additional problems beyond merely the water depth and the well depth required to reach the reservoirs. These exploration plays depend on understanding the updip fluvial/deltaic stratigraphic architecture and the potential for partitioning of reservoir-quality sandstones across the depositional shelf into the slope and basin floor environments. The Lower Tertiary is estimated to contain up to 15 billion bbl of oil. Current State of Multizone Technology The Generation IV multizone system has been deployed successfully in the Lower Tertiary by multiple operators. To the authors’ knowledge, the multistage completion system and enhanced single-trip multizone fracturing systems had been installed in 10 wells as of the summer of 2015, with additional well installations planned. These systems are rated to 10,000 psi, and the enhanced single-trip multizone tool system offering an open-hole variant was installed in one five-zone completion.

Novel Coiled-Tubing Perforation Technique and Stimulation in Carbonate Gas Well

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 18880, “Novel Abrasive Perforating With Acid-Soluble Material and Subsequent Coiled-Tubing Jetting-Assisted Stimulation Provide Outstanding Results in Carbonate Gas Well,” by Adrian Buenrostro, Nahr Abulhamayel, Usman Malik, Mohammad Bu Suwaileh, and Saad Driweesh, Saudi Aramco, and Alejandro Chacon, José Camilo Jimenez Fadul, and José Noguera, Halliburton, prepared for the 2016 International Petroleum Technology Conference, Bangkok, Thailand, 14–16 November. The paper has not been peer reviewed. Copyright 2016 International Petroleum Technology Conference. Reproduced by permission. Abrasive perforating with coiled tubing (CT) is a technique that has proved to be a valuable alternative to conventional perforating with electric line. The application is particularly valuable whenever a high rate or fracture-stimulation treatment is to follow because of the significant reduction in tortuosity and pumping friction losses across perforations. This paper discusses a novel approach to abrasive perforating, including the first-ever use of an acid-soluble abrasive material and ending with CT-jetting-assisted nitrified stimulation. Introduction Many carbonate gas wells located in the northern section of the Ghawar reservoir exhibit a low-permeability profile and are characterized by having low reservoir pressure. Fracture gradients in a formation in this area of the field are on the order of 1.12 psi/ft, which is considerably greater than that of more-conventional tight gas formations. One particular well, located on the flank of the reservoir, was designed to be completed with a plug-and-perforate acid-fracturing operation, but issues arose with this option that finally caused the abandonment of the fracturing treatment. To find a solution that would be feasible and economically viable, an innovative perforation and stimulation technique was engineered for this well. Design of the Perforation Technique and Yard Testing The team was able to source a newly developed acid-soluble abrasive material that enabled the same quality of perforations to be created without performing a cleanout run because the acid from the stimulation would dissolve the abrasive material, saving at least 2 days of operation. The abrasive material was sourced, and several yard tests were completed to determine if the material had the same abrasive characteristics as common 20/40- or 100-mesh sand. It was necessary to compare the time required to penetrate the steel and cement with the results obtained using common sand. This benchmarking was key to determining if additional time and fluid resources were necessary to obtain the same penetration. A yard test was set up with two metallic 55-gal drums cut halfway lengthwise and then welded together. This created a receptacle that allowed the team to place a 6⅝-in. casing section with 100% standoff and then fill the entire annular space with cement. The drum was then set on top of cement blocks, and the abrasive-jetting tool was introduced.

Methodology for assessing original gas in place and estimated ultimate recovery from a tight marine formation using hydraulic fracture stimulation modelling

Operators in Australia are currently exploring similar geological settings to the tight marine unconventional petroleum systems of the United States, in the hope of emulating the North American success. This study sets out the methodology and models required to undertake an analysis of a tight marine source and reservoir rock to estimate its production potential, with particular attention given to modelling the required hydraulic fracture stimulation. The project target formation is the tight marine Log Creek Formation, which forms the source rock to the overlying proved Gilmore Gas Field in the Adavale Basin in Central Queensland. The Marcellus Formation in the Appalachian Basin in the Northeastern United States is an assumed analogue to the Adavale Basin; data from the Marcellus Formation was used when unavailable for the Adavale Basin. Initially, formation evaluation was undertaken to determine key parameters such as total organic carbon (TOC), mineralogy and stress regime. Once the formation had been characterised, a fracture stimulation model was built to determine the hydraulic fracture stimulation treatment design, which optimised the lateral landing depth, hydraulic fracture spacing, conductivity and half‐length. In particular, it is important to determine the lateral landing depth and fracture half‐length with confidence, as they will define the stimulated reservoir volume (SRV), which sets the upper boundary on original gas in place (OGIP) and estimated ultimate recovery (EUR) of gas. OGIP was estimated using a probabilistic model incorporating an adjustment for absorbed gas volume. Finally, a reservoir simulation was undertaken using a single well composite multi‐fracture model to obtain EUR.

Ultra-deep Permian coal gas reservoirs of the Cooper Basin: insights from new studies

There is a vast, untapped gas resource in deep coal seams of the Cooper Basin, where extensive legacy gas infrastructure facilitates efficient access to markets. Proof-of-concept for the 5 million acre (20 000km2) Cooper Basin Deep Coal Gas (CBDCG) Play was demonstrated by Santos Limited in 2007 during the rise of shale gas. Commercial viability on a full-cycle, standalone basis is yet to be proven. If commercial reservoirs in nanoDarcy matrix permeability shale can be manufactured by engineers, why not in deep, dry, low-vitrinite, poorly cleated coal seams having comparable matrix permeability but higher gas content? Apart from gas being stored in a source rock reservoir format, there is little similarity to other unconventional plays. Without an analogue, development of an optimal reservoir stimulation technology must be undertaken from first principles, using deep coal-specific geotechnical and engineering assumptions. Results to date suggest that stimulation techniques for other unconventional reservoirs are unlikely to be transferable. A paradigm shift in extraction technology may be required, comparable to that devised for shale reservoirs. Recent collaborative studies between the South Australian Department of State Development, Geological Survey of Queensland and Geoscience Australia provide new insight into the hydrocarbon generative capacity of Cooper Basin coal seams. Sophisticated regional modelling relies upon a limited coal-specific raw dataset involving ~90 (5%) of the total 1900 wells penetrating Permian coal. Complex environmental overprints affecting resource concentration and gas flow capacity are not considered. Detailed resource estimation and the detection of anomalies such as sweet spots requires the incorporation of direct measurement. To increase granularity, the authors are conducting an independent, basin-wide review of underutilised open file data, not yet used for unconventional reservoir purposes. Reservoir parameters are quantified for seams thicker than 10feet (3m), primarily using mudlogs and electric logs. To date, ~3750 reservoir intersections are characterised in ~1000 wells. Some parameters relate to resource, others to extraction. A gas storage proxy is generated, not compromised by desorption lost gas corrections. A 2016 United States Geological Survey resource assessment, based on Geoscience Australia studies, suggests that the Play remains a world-class opportunity, despite being technology-stranded for the past 10years. Progress has been made in achieving small but incrementally economic flow rates from add-on hydraulic fracture stimulation treatments inside conventional gas fields. Nevertheless, a geology/technology impasse precludes full-cycle, standalone commercial production. A review of open file data and cross-industry literature suggests that the root cause is the inability of current techniques to generate the massive fracture network surface area essential for high gas flow. Coal ductility and high initial reservoir confining stress are interpreted to be responsible. Ultra-deep coal reservoirs, like shale reservoirs, must be artificially created by a large-scale stimulation event. Although coal seams fail the reservoir ‘brittleness test’ for shale reservoir stimulation practices, the authors conclude from recent studies that pervasive, mostly cemented or closed coal fabric planes of weakness may instead be reactivated on a large scale, to create a shale reservoir-like stimulated reservoir volume (SRV), by mechanisms which harness the reservoir stress reduction capacity of desorption-induced coal matrix shrinkage.

Study on a new water-inhibiting and oil-increasing proppant for bottom-water-drive reservoirs

Due to the high water content ratios after hydraulic fracturing stimulation treatments in the bottom-water-drive reservoirs, a surface modified quartz sand proppant with the performance of water inhibition and oil enhancement was developed. This surface modified proppant (YS03 proppant) indicates the following advantages, such as, no-heating in the preparation process, simple operation, and short reaction time, making it suitable for “On-the-fly” treatment, which will greatly reduce the impact of storage and transportation. The evaluation experiments show that the contact angle is up to 151° with little change even at 80°C, which indicates YS03 proppant has strong hydrophobicity. The crush rates of the quartz sand at 52MPa (69MPa) are reduced from 3.69% (10.30%) to 1.81% (5.11%), making it applicable to hydraulic fracturing. The core flowing experiments demonstrate that the NFRR is 5.51, and the fracture conductivity experiments show that YS03 proppant pack can effectively inhibit the flow of the aqueous phase and promote the flow of the oil phase. In addition, the fines adsorption experiments manifest that the YS03 proppant pack has an excellent self-cleaning property, which can maintain flow channels for the hydrocarbon production for a long time after the hydraulic fracturing treatment.

Integrated rock classification in the Wolfcamp Shale based on reservoir quality and anisotropic stress profile estimated from well logs

Reliable rock classification is the key to identify target zones for successful hydraulic fracturing stimulation treatment in unconventional reservoirs such as organic-rich mudrocks. Such a rock classification scheme should take into account geologic attributes, petrophysical, and geomechanical properties (i.e., in situ stress gradient and elastic properties) to improve the likelihood of successful fracture treatment. However, conventional rock classification methods do not take into account stress gradients in the formation. We have developed a new rock classification technique that integrates four rock classification schemes based on the (1) geologic facies, (2) reservoir quality, (3) stress profile, and (4) completion quality. The techniques applied in these classification schemes include core description and thin section analysis, well-log-based depth-by-depth petrophysical and compositional characterization, and analysis of geomechanical measurements. Geomechanical analysis of core measurements and well logs provide a depth-by-depth assessment of minimum horizontal stress assuming vertical transverse isotropy in the formation. We have performed the geologic facies and reservoir quality classifications using an artificial neural network analysis, in which well logs and well-log-based estimates of the petrophysical and compositional properties were inputs to the network. Our technique was applied to a well located in the Wolfcamp Shale in the Delaware Basin. Based on the integrated rock classification results, we recommend the middle of the upper Wolfcamp and the bottom of the lower Wolfcamp depth intervals as the best candidates for fracture initiation and fracture containment zones, respectively. The selection of these zones was based on the reservoir quality and average minimum horizontal stress gradient calculated in these intervals. Our integrated rock classification technique can improve the planning and execution of completions design for hydraulic fracture treatments.

Geomechanical modelling of fault reactivation in the Cooper Basin, Australia

ABSTRACTThe Australian Cooper Basin is a structurally complex intra-cratonic basin with large unconventional hydrocarbon potential. Fracture stimulation treatments are used extensively in this basin to improve the economic feasibility; however, such treatments may induce fault activity and risk the integrity of hydrocarbon accumulations. Fault reactivation may not only encourage tertiary fluid migration but also decrease porosity through cataclasis and potentially compartmentalise the reservoir. Relatively new depth-converted three-dimensional seismic surveys covering the Dullingari and Swan Lake 3D seismic surveys were structurally interpreted and geomechanically modelled to constrain the slip tendency, dilation tendency and fracture stability of faults under the present-day stress. A field-scale pore pressure study found a maximum pressure gradient of 11.31 kPa/m within the Dullingari 3D seismic survey, and 11.14 kPa/m within the Swan Lake 3D seismic survey. The present-day stress tensor was taken from previously published work, and combined with local pore pressure gradients and depth-converted field-scale fault geometries, to conclude that SE–NW-striking strike-slip faults are optimally oriented to reactivate and dilate. High-angle faults striking approximately E–W appear most likely to dilate, and act as fluid conduits irrespective of being modelled under a strike-slip or compressional stress regime. Near-vertical SE–NW and NE–SW-striking faults were modelled to be preferentially oriented to slip and reactivate under a strike-slip stress regime. Considering that SE–NW-striking strike-slip faults have only recently been interpreted in the literature, it is possible that many reservoir simulations and development plans have overlooked or underestimated the effect that fault reactivation may have on reservoir properties. Future work investigating the likelihood that fracture stimulation treatments may be interacting, and reactivating, pre-existing faults and fractures would benefit field development programs utilising high-pressure hydraulic fracture stimulation treatments.

Unexpected behaviors of stimulated fractures in the high-stress Cooper Basin

Much of the industry's experience with fracture stimulation comes from basins with low stress and normal fault regimes. The Cooper Basin has high differential stress. It is in a strike-slip fault regime for shallower reservoir levels and a reverse-fault regime for the deeper reservoirs of a new basin-centered gas play. This difference in stress leads to a difference in fracture-stimulation results. Presented here are data on Cooper tectonic stress, rock strength, pore pressure, natural fractures, and borehole breakouts all of which impact fracture-stimulation treatments. Several unexpected behaviors of Cooper fracture stimulations then are discussed and some mitigation suggested. The reader is assumed to be a geoscientist with an interest in this topic, not necessarily an expert in geomechanics or fracture stimulation.

Cultural and technical issues with development of unconventional reservoirs in Australia Petroleum keynote paper

Will development of unconventional reservoirs (tight gas, shale gas and CSG) in Australian proceed as in North America? What aspects of Australian development are more favorable? And what aspects will make development in Australia more difficult or expensive? Australia currently has a more challenging cost structure than North America, but there are some distinct hidden advantages in Australia's oil and gas permitting laws. Australia's gas market appears to be much more attractive, at least for the short to mid-term. And the environmental issues are playing out in Australia in a very similar manner to North America. Inside Australian companies developing unconventional resources, there is a debate over competing development philosophies that is largely hidden from public view; this is the debate between a low cost factory-like pattern drilling program versus an expensive up-front investment in geoscience data that will hopefully lead to a more economic drilling and completion solution. Within the subsurface technical realm, a common mantra in North America now is every shale gas play is different – meaning that a technical solution for shale gas development in one basin may not work in another basin. With this view, shale gas development in Australia will not be any more or less challenging than trying to adapt Barnett shale gas solutions to the Eagle Ford shale (which is highly successful) or to the largely disappointing Woodford Shale. But there is one significant development challenge common to Australian basins that has not been experienced in North American: higher tectonic stress and higher differential stress. These higher stresses can lead to horizontal fracture stimulation treatments instead of the expected and more favorable vertical frac treatments. While it is still too soon to pick the successful and unsuccessful unconventional plays in Australia, this talk will attempt to highlight the critical drivers in that success.

Geomechanic models using finite element methods show how Cooper Basin structure and sand body geometry impacts stress variation and hydraulic fracturing results

Unconventional reservoirs such as tight sands and shales require hydraulic fracture stimulation to improve productivity. The success of reservoir stimulation is controlled by the local stress field but decisions are often made knowing only the average stress field. This study uses geomechanical modelling to help explain lateral stress variability using structural geology, lithology contrast and boundary conditions. Changes in vertical and horizontal stresses are related to depth, lithology and structural position, yet these effects are not always accounted for. This is evident in the Cooper Basin, Australia, where, for example, unexpected changes in minifrac pressure are commonly observed in adjacent wells in a field. This study presents results from conceptual geomechanical models to help explain such variations in stress. Model scenarios are constructed using finite element package to investigate the impact of structural position, rock mechanical properties and stress regime on the patterns of horizontal and vertical stress magnitudes in a layered antiform sequence. Key findings suggest that: stress magnitude is affected by structural positioning; different patterns of stress exist across different lithologies; and, stress regime impacts on patterns of stress, especially in combination with curvature of structures. These challenge traditional methods of one-dimensional mechanical earth models and show that, rather than employing methods developed for simple layer-cake geology in extensional basins, geomechanical models should be constructed in two- or even three-dimensions. Results of this study highlight part of the solution to the unconventional resource potential of the Cooper Basin. Improved prediction of field-scale stress variations should enable further optimisation of hydraulic fracture stimulation treatments.

Sequence stratigraphic principles applied to the analysis of borehole microseismic data

Based on a sequence stratigraphic framework developed using gamma ray stacking patterns, we have identified brittle-ductile couplets, which allow us to better interpret the microseismic response recorded during a single-stage hydraulic fracture stimulation treatment monitored from three strategically located observation wells. We have analyzed and compared hydraulic fracturing results inferred by individual processing of microseismic data acquired from horizontal and vertical sensor arrays, as well as the results from simultaneously processing the signals recorded by all three sensors. Ultimately, we have decided in favor of the triple array simultaneous solution as the most useful data set to interpret the stimulation treatment due to the location of the microseismic events coupled with the theoretical expectation from our sequence stratigraphic framework. The final data set has not only allowed us to better interpret the hydraulic fracturing results, but also helped us improve recommendations in support of the field development campaign.

Leak-Off Coefficient Analysis in Stimulation Treatment Design

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

Enhancement of CBM well fracturing through stimulation of cleat permeability by ultra-fine particle injection

Coal permeability declines due to fracture closure during the dewatering stage. A new technique for stimulation of natural coal cleats through ultra-fine and ultra-light high-strength particle injection into a coal fracture system is proposed. Coupling this technique with hydraulic fracturing treatment resulted in particles entering cleats under leak-off conditions. The following optimal water-based coreflood experimental conditions were determined by applying Derjaguin-Landau-Verwey-Overbeek (DLVO) theory to the interaction between glass particles and the coal matrix: stability of a particle-based suspension (no agglomeration); repulsion between particles and the coal matrix; and, immobilisation of coal natural fines. At these conditions, these particles were placed inside cleats and were not attached to the cleat entrance, leading to less external cake formation; no formation damage due to fines migration was observed. The experimental study was carried out on some bituminous coal samples. Micro-sized glass particles were injected into a coal core at minimum effective stress until core permeability decreased to a value predetermined by a mathematical model. An increase of the effective stress to its maximum value by injection of particle-free water resulted in an approximate three-times increase in coal permeability, when compared to the original value. The proposed technique can be used for stimulation of a natural fracture network in conventional and unconventional reservoirs, as well as for the enhancement of conductivity of micro-fractures around the hydraulically induced fractures. These particles can be used as a non-damaging leak-off additive during hydraulic fracturing stimulation treatments leading to long-term fracture conductivity.