Raymond L. Johnson

Improving results of coalbed methane development strategies by integrating geomechanics and hydraulic fracturing technologies

Hydraulic fracturing has been a key technology in the development of coalbed methane (CBM) resources worldwide. Obtaining adequate fracture length and conductivity has limited the ability to obtain adequate productivity improvement to further develop many small seams or stacked-seam reservoirs. Fracture complexity and growth out of the interval have frequently been cited as limiting factors in achieving optimal length in these types of intervals; however, the diagnostics to evaluate and model these effects have been limited. Finally, many of the past studies of hydraulic fracturing mechanics in coal have been focused on North American examples where normal faulting stress states are present, unlike many of the coal-producing basins worldwide and particularly in Eastern Australia. Using examples from the Scotia Field, we describe how past and present stress framework analyses and post-frac treatment diagnostics were integrated to better describe the in-situ stress state. Through analyses of these examples, we qualify the inter-relationships of productivity to in-situ stress, pre-existing fractures, and observations from the induced hydraulic fractures. Finally, we describe cases where the hydraulic fracturing complexity and in-situ stress conditions lead to wellbore complications and observable rock-mechanical failures. The end result is a more predictive model, which is being used to develop this CBM resource.

Evaluating Hydraulic Fracture Effectiveness in a Coal Seam Gas Reservoir from Surface Tiltmeter and Microseismic Monitoring

In developing new coalbed methane (CBM) or coal seam gas (CSG) fields or reservoirs, the effect of many parameters are important in understanding the success or potential areas for improvement of hydraulic fracturing treatments. Estimating fracture geometry relative to the reservoir architecture is critical to understanding production variability. The Walloon Coal Measures, in the Surat Basin of Eastern Queensland, Australia, are a complex reservoir containing interbedded sandstone, siltstone, carbonaceous shale and coal seams where initial attempts at hydraulic fracturing in early pilot areas of the Surat Basin yielded poor results. Thus, when a hydraulic fracturing program was planned for this reservoir, it was decided to integrate a group of diagnostics that would be useful in understanding past results as well as deriving future improvements. Data is presented from two wells in the Walloon Sub Group (WSG) where tiltmeters and microseismic monitoring were used to evaluate fracture effectiveness relative to the reservoir architecture and to assist further design work. The treatments carried out in the studied wells were typical of CSG frac treatments used in other producing areas, incorporating stages of treated, gelled and crosslinked-gelled water with increasing concentrations of sand, up to six (6) lbm/gal. During the treatments, complex fractures were inferred based on analyses of data from both tiltmeter and microseismic monitoring methods. The collaborative data set for these wells also included a large amount of other analyses and diagnostic data. It was only possible to fully explain the treatment results through the combination of multiple diagnostics and an in-depth understanding of how the created fracture interacted with the complex reservoir and stress environment. In this paper, we outline the steps used to plan the monitoring program and describe how geological data was integrated to better understand the results observed during the treatments. We describe each of six (6) stages performed across the two wells, and how the diagnostics did or did not support the overall conclusions as to the effectiveness of each stage. Finally, this paper presents a logical framework to evaluate and integrate these technologies for use in future CSG well stimulation. Copyright 2010, Society of Petroleum Engineers.

Utilizing current technologies to understand permeability, stress azimuths and magnitudes and their impact on hydraulic fracturing success in a coal seam gas reservoir

In coal seam gas (CSG), also known as coalbed methane (CBM), appraisal, the development potential of a play requires an understanding of the interrelationship between stress and permeability, critical elements in defining deliverability and hydraulic fracturing effectiveness. Unfortunately, the interdependency of these variables may not emerge until the post-treatment evaluation of a hydraulic fracturing treatment. Herein is an example from the Walloon Subgroup (WSG), Surat Basin, where regional data were used to target a small, localized, structural setting for CSG appraisal and subsequent hydraulic fracturing. Due to the rank of the WSG coals in this area, the cleat network was deemed to be immature and permeability is understood to be derived from exogenetic fracturing from external stresses acting on the coal, creating a unidirectional fracture network. The fractures are commonly constrained to brittle lithologies and truncate at bedding boundaries, while evidences exist of minor low angle faulting in non-reservoir lithologies. Eventually, the local stress regime was determined from the petrophysical log data, injection stress testing, and subsequent one-dimensional (1D) mechanical earth model (MEM). Ultimately, these data support the proposed reservoir and stress environment. We will show how data were acquired, evaluated and integrated to support the development of the 1D MEM and aided the interpretation of the hydraulic fracture treatment results. While localized, the results of this evaluation indicate a potential pitfall can exist in some CSG environments. This case illustrates a scenario where stress and dominant permeability axes can be properly aligned to maximize hydraulic fracture effectiveness, but where sub-optimal stress magnitudes prevent achieving the full benefit of the hydraulic fracturing process.

Evaluating Hydraulic Fracture Geometry from Sonic Anisotropy and Radioactive Tracer Logs

In developing a new field or reservoir, many parameters are important in understanding the success or possible areas for improvement in hydraulic fracturing. Estimating fracture geometry is essential to effectively calibrate a reservoir model to production results. Radioactive (RA) tracers have been used in hydraulic fracturing treatments to infer fracture dimensions. Three stable isotopes (i.e. Scandium, Iridium and Antimony) were used in various parts of the treatment to understand the progression of hydraulic fracture growth. Advanced sonic anisotropy logging tools, using a broader range of frequency acquisition, were used to enable shear measurement in cased hole environments over a wide range of interbedded coal, shale and sandstone sequences both before and after the hydraulic fracture treatment. Amplitude and anisotropy changes after a hydraulic fracture have been measured using sonic anisotropy logging and used to infer fracture height. Finally, the sonic anisotropy can be evaluated above and below the perforated interval and investigate hydraulic fracture height growth away from the wellbore, potentially visualising a greater distance than available with RA tracers. We will show how sonic anisotropy and radioactive tracer logging methods can be used to better understand the fracture geometry and aid further design work. The paper will present data from two (2) wells in the Walloon Coal Measures of the Surat Basin where both RA tracers and sonic anisotropy logs were used to infer fracture dimensions. Both wells used a combination of treated water stages, containing low concentrations of proppant, followed by borate-crosslinked gelled water stages with higher concentrations of proppant. This project contained a large amount of other hydraulic fracturing diagnostics including treatment pressure history-matching, microseismic monitoring and surface tiltmeters. In this paper we will note how those diagnostics compared with the results presented herein, but their results are discussed in greater detail elsewhere (Johnson et al. 2010a). Generally, the results indicate good agreement between these two fracture diagnostic methods and the authors will illustrate the complimentary nature of these diagnostics in gaining a fuller understanding of fracture height, especially in environments of complex fracture development.

Reservoir Characterisation of Surat Basin Coal Seams using Drill Stem Tests

Drill Stem Testing (DST) is a primary means of evaluating skin and permeability of exploration and appraisal wells. It is no exception in the case of Coal Seam Gas (CSG) reservoirs. A modified form of DST is routinely used by the CSG industry in this region (Queensland, Australia) as a low cost means of getting skin, permeability and pressure information for these land based wells which have to be mass-drilled given the nature of these coal seam reservoirs and the well productivity. In this paper we review about 450 individual DSTs with a variable permeability and skin values. Observed high skin and permeability values from many of these wells called for better understanding of these parameters in conjunction with core and log data. About 50 wells in the subject study were cored. Image logs were run in addition to routine openhole wireline log suite. Some of the abnormal (very high) skin and permeability values could be explained from detailed analysis of these logs. Examples of DST, log and core data reconciliation have been reviewed. Various studies have been conducted to understand root causes of the observed high skin values. Well interference tests have been conducted to understand horizontal permeability anisotropy and reservoir continuity. This DST, log and core assisted reservoir characterisation has opened the way for completion optimisation for more than 6000 wells to be drilled in the Surat Basin, Queensland, Australia.

Stimulation of Unconventional Naturally Fractured Reservoirs by Graded Proppant Injection: Experimental Study and Mathematical Model

The coal permeability declines due to fracture closure during the production and pressure depletion. The recently proposed technique for stimulation of natural coal cleats consists of the injection of microsized high-strength particles into a coal natural fractured system below the fracturing pressure. Coupling this technique with hydraulic fracturing treatment resulted in particles entering cleats under leal-off condition. In the current paper it is shown that the particles must be deposited at specific conditions of the particle-coal repulsion, ensuring the absence of external cake formation. The new method was successfully validated through laboratory injection of microsized glass particles into fractured coal cores. Application of Derjaguin-Landau-Verwey-Overbeek (DLVO) theory resulted in determination of experimental conditions favourable for particle-particle and particle-coal repulsion; these conditions also immobilize the natural fines. At these conditions, no particle attachment to coal surface and no particle agglomeration were observed, thus the conditions exclude formation damage due to external cake formation, particle attraction to coal rock and fines migration. The previously developed mathematical model was used for determination of the duration of particle injection into a coal core at minimum effective stress. Particle placement resulted in almost three-time increase in coal permeability, thus confirming the mathematical model used. The curve for well productivity index-vs-stimulation zone radius reaches maximum at some critical value of stimulation radius; the maximum is determined by the mathematical model. Placing particles beyond this critical radius results in reduction of well productivity index, due to significant hydraulic losses experienced by suspension flowing through narrowing cleat apertures during production stage. Applying the proposed novel technology during hydraulic fracturing treatment leads to improvement in productivity of coal seam gas wells and other unconventional resources (shales, tight gas and geothermal reservoirs) through enhancement of interConnectivity among microfractures around the hydraulically induced fractures.

Managing Uncertainty Related to Hydraulic Fracturing Modeling in Complex Stress Environments with Pressure-Dependent Leakoff

This paper demonstrates where alternate approaches to BHTP analysis and modeling can provide significantly differing potential stimulation treatment geometries, outcomes, and go-forward strategies. We will illustrate this conundrum using cases from the greater Cooper/Eromanga Basin of Central Australia; these cases commonly indicate an interrelationship between production outcomes, the magnitude of in-situ stress and the onset pressure or severity of pressure-dependent leakoff. Historically, treatments can be placed in these environments either after performing numerous diagnostic injections, by increasing pad volumes or by increasing injection fluid viscosity. However, these repeated injections and design alterations may only serve to stabilize the injection environment potentially masking the problem or causing production damage. We offer recommendations and explore different methods to mitigate these effects in cases where high stress and pressure-dependent behavior are indicated. We demonstrate how strain-corrections are used to correct log-derived rock mechanical properties to history-match initial BHTP responses. The cases presented use either: (1) increases in near-wellbore or near-fracture reservoir pressure; (2) changes in stress due to fracture propagations or horizontal loading; or (3) reductions in pressure-dependent leakoff coefficients to history match subsequent injections over multiple days. Finally, we indicate for each of these complex cases where production results or the desired treatment outcomes may have been altered by repeated diagnostic injections or a job changes.

The Pressure-Dependence Ratio: A Bottomhole Treating Pressure Diagnostic Tool for Hydraulic Fracturing in Tight, Naturally Fractured Reservoirs

As we continue to develop the processes of hydraulic fracturing in tight, naturally fractured, reservoirs, so continues our development of more effective bottomhole treating pressure (BHTP) diagnostics. New diagnostic techniques need to reflect the physical processes and give insight to potential damage mechanisms prevalent during hydraulic fracture treatments in these complex reservoirs. In this paper, we provide a thorough evaluation of BHTP trends observed during fracturing treatments performed in the Barnett Shale, a naturally fractured shale reservoir. From this evaluation, we are able to propose a new, more effective tool that can be combined with other BHTP and fracturing diagnostic techniques. Further, this analytic technique is easily adaptable to the treatment of other tight, naturally fractured reservoirs to enhance design or on-site decisions.

Changes in Completion Strategy Unlocks Massive Jurassic Coalbed Methane Resource -The Walloon Subgroup, Surat Basin, Australia

Since the late 1990s, operators have drilled a number of coalbed methane (CBM) core and exploration wells to define the gas resource potential of the vast and relatively unexplored Jurassic Walloon Subgroup (SG) in the Surat Basin. Unfortunately, early pilots used completion techniques that failed to fully assess the true potential of this reservoir. Firstly, openhole completions were trialed but had limited success because of fines influx and well collapse. Next, cased and cemented wellbores incorporating hydraulic fracturing stimulation treatments were attempted to improve wellbore stability, reduce fines influx and increase gas production; these wells were ineffective and many experienced problematic casing failures. Finally, an isolated, openhole, under-reamed completion technique was trialed and achieved commercial flow rates representative of the drill-stem testing data indicated from earlier exploratory drilling. This paper describes the process, experiences and results leading to the present completion strategy. We note production, permeability and skin factors associated with early completions, as well as results obtained from large-scale implementation of this more effective completion method. As a result of this change, the resource potential of the Walloon SG has grown significantly and the operator has proven 3,712 Bcf of reserves from a previously undeveloped resource area.

Graded Proppant Injection into Coal Seam Gas and Shale Gas Reservoirs for Well Stimulation

Alireza Keshavarz, Alexander Badalyan, Themis Carageorgos, Pavel Bedrikovetsky, and Ray Johnson Jr.