SPE Asia Pacific Unconventional Resources Conference and Exhibition

To evaluate the exploration potential of tight oil reservoirs in the Upper Triassic Yanchang Formation, a combined research was done to investigate the source rock distribution, diagensis, pore systems, petrophysical parameters. To begin with, the horizontal distribution and vertical thickness of the reservoir were clarified with data from well drilling and regional geological background. After that, X-ray diffraction and scanning electron microscopy experiments were conducted to study the pore types and morphologies. Then the pore size distribution was calculated based on mercury injection capillary pressure data. Finally, porosity and permeability were tested. Also, the causes of the tight sandstone, the controlling factor of petrophysical parameters and the fracability were discussed.

The Upper Triassic Yanchang Formation is rich in tight oil reserves and shows good exploration potential. Horizontally, reservoir is accumulated at the centre of the lake deposit with an area of 7.5×10³ km²; vertically, reservoir is in Chang 6, Chang 7 and Chang 8 member with total depth 25–80m, among which Chang 7 member acts as the main source rock. Sediments are mainly fine grained sand, cements including clays, calcite and dolomite. After early stage mechanical compaction and late stage cementation, the reservoir becomes quite tight. Pores are classified into four types, residual interparticle pores, intraparticle grain pores, clay dominated pores, and micro fractures. Residual interparticle pores and clay dominate pores are main pore types for storage and flow; existence of micro fracture can improve permeability and is a good indication of fracturing potential. Porosity is between 6.12–13.80% and air permeability normally smaller than 0.3 mD, the early stage compaction is the main reason of porosity reduction, while combination of compaction and cementation results in dramatic decreasing in permeability. This reservoir can be commercially developed with horizontal well and hydraulic fracturing stimulation.

This study provides a workflow to fully characterize the storage and transport properties of a tight oil reservoir, and the workflow can act as reference to other similar reservoirs.

Oil and gas wells are required to be plugged when the production of these wells is no longer economical. Cement is the current standard method for plugging wells. However, this process has limitations because cement is expensive and prone to cracking and unsealing. This paper aims to review and investigate the use of a naturally occurring clay called bentonite to plug CSG wells in Queensland as well as oil and gas wells in general. Bentonite is cheaper and easier to handle and when hydrated it creates a more reliable plug because it is malleable and self-healing when disturbed.

We also experimentally and theoretically investigate the mechanisms for failure of bentonite plugs. The plug failure mechanisms can be determined by comparing the measured dislodgement pressure and the predictions of the theory developed in our group. Based on our preliminary results we found that the hydrated plugs can be made significantly stronger by restricting the expansion space. This allowed us to measure the internal swelling pressure at 8 MPa which corresponded to measurements reported in the literature at a reduced density of 1.6755 g/cm³.

The Australia Pacific LNG Project is scheduled to come online in 2015 and consists of the extensive development of substantial coal seam gas resources across the Surat Basin. A variety of unique and complex challenges are presented when undertaking the geological and dynamic modelling and performance prediction of the laterally discontinuous and thin coal seams within the Walloons package. These challenges require a targeted approach and evolving solutions.

Specific challenges that have been assessed and addressed in the characterisation and modelling workflow of the complex Walloons coal seams include:

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Complex coal packages exhibiting thin coal seams with high degrees of lateral and vertical heterogeneity

The developed workflow addresses coal seam gas modelling challenges both within the history matching phase and in the subsequent probabilistic forecasting. The workflow identifies uncertain reservoir properties and their expected maximum ranges based on available data and previous studies. An uncertainty analysis is conducted with statistical approaches including Tornado Chart and Latin Hypercube (LHC) to identify the most influential reservoir parameters and fine-tune their ranges in order to optimize the probabilistic history matching process. Subsequently, assisted history matching and optimisation techniques follow a stochastic algorithm of experiments to reduce the mismatch and create convergence with the production history. A number of representative, non-unique history matched models are identified which satisfy matching criteria and capture the uncertainty of the subsurface.

The selected acceptable history matched models, together with forecasting parameters and their ranges, including operational variables, are used in forecasting. Random sampling of uncertainties by LHC is used with assisted history matched cases resulting in thousands of forecasts based on which P10-P50-P90 probabilistic forecasts are selected.

This paper presents solutions to address uncertainty, assisted history matching and performance prediction of the Walloons coal measures for rigorous forecasting, and incorporation of learnings from localized fine scale models into larger coarse scale modelling for time efficient, regional performance prediction.

Multiple cluster perforations are typically used for multi-stage hydraulic fracturing of horizontal wells with casing hole completion to create multiple fractures in any single stage. Due to the mechanical interaction of fractures, the local principal stresses field may alter, which affects the fracture complexity. To optimize the network fracturing design, 3D multiple fractures propagation, stress distribution and fracture mechanics need to be well considered.

Firstly, The geometry model for Fuling shale gas formation has been Established, with A depth varying initial in-situ stresses, pore pressure and permeability defined. Then, a linear Drucker-Prager model with hardening is chosen for the rock, while the casing is linear elastic. Based on damage initiation of quadratic nominal stress criterion and damage evolution of B-K critical energy release rate criterion, the tensile and shear mixed mode fracture model consists of the mechanical behavior of the fracture itself and the behavior of the fluid that enters and leaks through the fracture surfaces.

Through the selection of general purpose finite element code ABAQUS, the multiple 3D fractures propagation process and stress interferences between fractures have been modeled. The results illustrate that mechanical interaction exists between any pairs of fractures, which greatly influences the stress distribution and the geometries and widths of the fractures. Induced stress increase is stronger in magnitude and influences larger region for the minimum horizontal stress than for the maximum horizontal stress. Spacing of perforation clusters and net pressures are two important factors for the successful application of network fracturing. It is possible that the cumulative interaction effect of several fractures could neutralize the stress anisotropy in the formation to enhance the fracture complexity. Taking advantage of the altered stress in the rock for a base case with three fractures, an adequate range of perforation clusters spacing and net pressure are determined for the network fracturing of horizontal wells in Fuling shale gas reservoir, and the treatment design is optimized accordingly.

This numerical procedure combined with the post-fracture production rate is also used to evaluate the efficiency of network fracturing for multi-stage fractured horizontal wells in Fuling formation, which can be served as a guidance to optimize the treatment design not only for Fuling but for other shale gas and tight gas reservoirs.

In this text the authors present a study on the approach of estimating the lost gas during the retrieval process of coal sample within wellbore. A new method is proposed to improve the accuracy of prediction as the traditional methods often give inaccurate predictions. To this end, the major sources of errors with those traditional methods are first analysed. Then the pertinent modifications are made in this proposed method to have these errors minimised. With the present method the following improvements are made. (1) Physically, the transport equation used here for gas flow in the core includes both advection and diffusion effects; in contrast, the traditional methods are fundamentally based on a linear diffusion equation. (2) Geometrically, the present method considers the the actual shape of the core sample (say, a cylinder), while the routine counterparts have to simplify the geometry of the core to be a one-dimensional spherical object. (3) Numerically, the present method employs the actual retrieval history to specify the boundary conditions of the core sample, and uses a neural network technique to best fit the measurements with the numerical solutions obtained. In contrast, the routine counterparts need to assume a constant or a linearly declining boundary condition such that an analytical solution (in a form of a series) can be obtained. When the relevant sorption isothermal curve for the coal is known, the proposed model contains three parameters to be determined, which are related to the effective permeability, the effective diffusion coefficient, and the initial gas content, respectively. These parameters are determined through best-match of the experimental data by the neural network simulations. An application example is presented in this study and it shows that the proposed method can significantly improve the accuracy of prediction for the lost gas volume or the initial gas content than its traditional counterparts.

The Changbei basin centred gas reservoir is located in the Palaeozoic clastic sandstone of the Shaanxi formation, Ordos basin, P.R. China. After more than a decade of successful tight gas production history, the development of the field is being expanded to include new target reservoirs. Because of its low intrinsic permeability, hydraulic fracturing stimulations are required to achieve commercial production rates from the target formation.

Fracture diagnostics suggests high fluid efficiencies in a normally faulted stress regime. Recent monitoring data of hydraulic fracturing stimulations during an appraisal campaign indicate fracture height growth containment which is not readily predicted by the current numerical simulators. Non-radioactively traced proppant and post-injection temperature logs suggest that fracture height may be controlled by a combination of stress barriers and shale laminations. However, the current numerical simulators tend to have difficulty predicting the termination of height growth without calibration to post-job data.

A new hydraulic fracturing code currently under development has been used to simulate the fracture treatments in the target formations. This study briefly describes the input data workflow for the new software and highlights the underlying models the simulations are based upon. The discrepancies between the model results are discussed and possible explanations put forward. The study concludes that the new code is a useful addition to the existing software, and that the thermodynamic module enables genuine comparisons with the temperature logs, which in this case are important for investigating the fracture development. The code also gives promisingly accurate pressure evolutions during the treatment when compared to measurements from a well equipped with a downhole gauge.

A range of mathematical models and correlations is used to estimate the pressure drop for co-current two-phase flows in vertical wells in the conventional oil and gas industry. However, in the annulus between casing and tubing of a coal seam gas (CSG) well, the upward flow of gas and downward flow of water results in counter-current two-phase flows. The flow regimes developed in such a counter-current system are noticeably different to co-current flow regimes, and thus the existing models used to predict pressure profiles in co-current wells do not adequately describe two phase flows in a (pumped) CSG well.

In this study, we modified existing mechanistic models for co-current flow and counter-current flow in a pipe to predict liquid holdup and pressure profiles of counter-current flows in vertical annuli for the slug flow, which is the dominant flow regime. A model, based on the work of Taitel and Barnea (1983), was also developed to predict the transition from slug flow to annular flow in counter-current flows in annuli. Our comparison of the pressure profiles of co-current and counter-current flows in annuli for the slug flow regime indicates that the pressure loss of counter-current flows could be appreciably different to that in co-current flows under the same conditions. This highlights the need to modify the models that are currently applied in typical commercial well flow simulators to better predict the pressure drop across CSG wells.

The structure of the fracture network formed by hydraulic fracturing operation is one of the key parameter in production from unconventional shale reservoirs. The standard approach to obtain such information is usually through well-testing coupled with micro-seismic monitoring. Unfortunately, the micro-seismic mapping is not always carried out and the conventional well-test techniques often fall short in describing the flow in shale reservoir in particular the contact area of the fractures open to flow.

The other alternative technique to get insight into structure of the fracture network is to use chemical tracer tests. In this study, we propose a new simple and cost efficient technique to estimate the fracture contact area by tracking the major exchange cations in shale reservoirs.

The idea behind the proposed technique is to replace the major cations on fracture surfaces in shale by increasing the concentration of one of the major cation in fracturing fluid. The current technique is satisfied the industry standard practice as the high concentrated K+ is part of hydraulic fracturing fluid composition and therefore cation exchange with other major cations (Na+, Ca++ and Mg++) is expected to occur.

In order to test the feasibility of the proposed techniques, a set of laboratory tests were conducted where a shale sample was milled and sieved to three different sizes to have different contact area. They are then placed in a high pressure cylinder (built for this study) and were washed by concentrated NaCl solution under high pressure and controlled temperature. The effluent was collected successively and analysed for major cations using ICP-MS. Correlation relating the cation exchange mass content to contact surface is proposed and calibrated using the data obtained from laboratory tests.

We shall discuss the following objectives: the use of Multivariant Analysis (MVA) to identify and classify important performance variables implemented in the hydraulic fracture treatment strategies. We shall discuss field optimization workflows initially performed in the Pinedale asset in Wyoming. Data were collated from multiple fluvial sand layers that aggregate across the anticline structure under study. Initial exploratory data analysis and bivariate analyses fell short of a comprehensive appreciation of the multivariate, stochastic and multivariant nature of this complex heterogeneous system. The MVA approach addressed the complexity "inherent in the data's coincident variation in multiple parameters. Data clustering was used to create different models and assess different parameters. Models were able to identify the relative impact of the most significant variables affecting stage production performance, and develop probability distributions for potential outcomes at different categories of production. A neural network was chosen to evaluate both reservoir parameters as well as variables that are controlled by the operator such as proppant volume and flowback methods."¹

"Evaluation was conducted on 195 stages of which 49 were identified as candidates for increase in proppant volume. Through this process the authors identified a need to update the model to include the impact of pressure depletion from down spacing. Even in the absence of accounting for pressure depletion the team experienced excellent results."¹

The goal is to design as efficient a completions strategy as possible across the anticline as more wellbores are drilled. Capturing the knowledge garnered from the geological parameters to maximize reservoir contact and the proppant volumes deemed appropriate across each stage of the wellbore, it is feasible to implement a function that identifies the values of operational parameters to maximize production. We can also identify which stages are most productive and shut down those stages that are under performers to reduce operational expenditure.

Unconventional resources in Saudi Arabia symbolize an opportunity to extend required gas plateaus in the long term, to substitute gas for liquid fuels, and to provide potential feedstock for the growing chemical industry. This paper aims to outline an integrated completion engineering and geosciences approach that was applied in the Jafurah shale gas play. The goal was to address complex unconventional reservoirs and their associated challenges, and to determine the optimum completion and fracture design.

Sweet spot identification within the Jurassic Tuwaiq Mountain Formation in the Jafurah basin represents a major challenge as it requires a large number of wells drilled over a wide geographical area with high associated costs. This requires innovative drilling, completion and stimulation practices. In order to identify and maximize potential frac stages and placements, a comprehensive study was completed using an advanced workflow encompassing drilling, geophysics, geomechanics, reservoir characterization, completion and fracturing and microseismic monitoring.

The targeted Jurassic Tuwaiq Mountain rocks are calcareous and interpreted to have been deposited in a restricted marine environment within an intra-shelf basin. This shale carbonate play shows a high Total Organic Content (TOC), low clay content, good matrix permeability, high gas saturation and high effective porosity. Scanning Electron microscope (SEM) images exhibit a dominant presence of organic porosity associated with the kerogen. Initial results from vertical wells drilled in the Jafurah basin proved that proppant fracturing can be successfully placed, and indicated the presence of a potential gas rich play within the same source rock. Subsequent horizontal wells were the first liquid rich/gas carbonate horizontal wells with ultra-low shale permeability in Saudi Arabia. The first horizontal wells had excellent gas production with significant amounts of condensate.

By further building on experience from the drilled and stimulated wells, the lessons learned provide a foundation for the completion of future unconventional gas wells in the Jafurah basin.