Implications of Geomechanical Analysis on the Success of Hydraulic Fracturing: Lesson Learned from an Australian Coalbed Methane Gas Field

Abstract

Hydraulic fracturing is a widely used technology in the petroleum industry to increase production rates from low-permeability reservoirs. It has also been successfully applied to coalbed methane gas development in many occasions. This paper presents an Australian field case of coalbed methane gas development where expensive fracture treatments did not yield the expected benefits. A comprehensive integrated geomechanical analysis was performed to understand the underlying causes for the failure. The geomechanical model consists of the magnitude and orientation of the three principal stresses, the pore pressure, and the rock strength. Fracture treatment data were used to estimate the least principal stress, vertical stress was determined from density logs, pore pressure was derived from direct field measurements, and rock strength values were determined from well logs and core measurements. The maximum horizontal stress (SHmax) magnitude was constrained by modeling the stress and pressure conditions consistent with the observation of wellbore breakouts in image logs. The relative magnitude of principal stresses corresponds to a transition between Strike-Slip and Reverse Faulting stress regimes (SV< Shmin < SHmax) with an overall SHmax orientation of NE-SW. Fracture propagation simulations using boundary element modeling showed that a complex fracture growth under the influence of the current in-situ stresses could be the main reason for the fracture treatment failure. The study recommended a number of alternative configurations for well orientations and fracture treatments in the field considering the existing in situ stress and the complex fracture network. Also the interactions between the coal seam and different fracturing fluids have been studied to evaluate the formation damage aspects to recommend the formation compatible fracturing fluid. Presentation of these results in this paper is expected to give a general framework for successful hydraulic fracture treatments and example of specific implementation issues with respect to an Australian coalbed methane gas field. Introduction Hydraulic fracturing is a process whereby proppant-laden fluid is injected into a well under high pressure to initiate a fracture from the wellbore wall and extend the fracture deep into the reservoir. Once the injection is ceased, the propped fracture becomes the principal conduit for flow of the hydrocarbon from the reservoir to the well, and thus achieving increased production rates. The petroleum industry has long been applying hydraulic fracturing treatment as a principal technique to improve oil and gas production. Of the production wells drilled in North America since 1950s, about 70% of gas wells and 50% of oil wells have been hydraulically fractured1. The technology has also been applied to many Coal Bed Methane (CBM) reservoirs. Improved design and execution of hydraulic fracturing treatments is, therefore, an important task in the petroleum industry. In fact, high demands for fracturing treatments in the industry have led to the wide commercialisation of this technology. Despite many success cases, the operational performance and cost-benefit accounts of hydraulic fracture treatments have not been positive in some occasions, particularly onshore Australia2. Major difficulties encountered during treatments include the requirement of high injection pressure, high frictional pressure drop, inability to inject proppant at required concentrations within the pump capacity, inability to extend the initiated fracture, and consequently, poor post-stimulation productivity. These experiences in usual sandstone reservoirs have also been recently encountered in a (CBM) gas field in Australia (name withheld due to confidentiality agreement). Further improved understanding is, therefore, necessary to design and execute treatments that would be effective for such unconventional field conditions. Without field-appropriate design and execution of treatments, there is very little chance that fracturing programs will be successful to realise its potential benefits commensurate to its investments and expectations. This paper presents the Australian CBM field case where fracture treatments were unsuccessful. The objective of this paper is to investigate the causes for failures of the treatments carried out through an integrated geomechanics analysis and to suggest measures that could be taken to increase the likelihood of success.

The effect of rank, lithotype and roughness on contact angle measurements in coal cleats

“…Most laboratory studies that report relative permeability in coals measured by steady state or unsteady state core flooding methods derive a crossover point water saturation fraction (S w ) exceeding 0.5, which is usually interpreted as the coal being water wet or hydrophilic (Conway et al, 1995;Durucan et al, 2013;Ham and Kantzas, 2011;Purl et al, 1991;Rahman and Khaksar, 2007;Shen et al, 2011). However, a problem with this standard approach is that it reports an average relative permeability for the core which assumes that the core has a uniform composition, homogenous wetting state and that the effects of capillary pressures are negligible.…”

The Effect of Water Occlusion on Gas Production in Coal

“…Experimentally measured relative permeability using coal cores in the laboratory under steady or unsteady methods detail a cross-point water saturation fraction in the relative permeability curve exceeding 0.5, implying coal is water wet (Conway et al, 1995a;Durucan et al, 2013;Ham and Kantzas, 2011;Purl et al, 1991;Rahman and Khaksar, 2007;Shen et al, 2011 (Kaveh et al, 2012;Saghafi et al, 2014), gas desorption (Ham and Kantzas, 2008;Ham and Kantzas, 2011), mineral matter (Gosiewska et al, 2002b) and liquid characteristics including ion concentration (Albijanic et al, 2010;Mishra et al, 2002) and pH (Chaturvedi et al, 2009). Coal rank is also another important factor that contributes to coal wettability, as high rank coal, such as anthracite are not water-wet, yet low rank coal like peat has both a high moisture content and is waterwet (Moore, 2012).…”

“…Some studies that measured relative permeability of coal cores in the laboratory using steady or unsteady method detailed a cross point water saturation fraction exceeding 0.5, implying coal is water wet (Conway et al, 1995a;Durucan et al, 2013;Ham and Kantzas, 2011;Purl et al, 1991;Rahman and Khaksar, 2007;Shen et al, 2011). However, experimental results have also shown that coal may have a mixed wetting state based on mineralisation, pressure, gas desorption, rank, lithotype, and pH (Gash et al, 1992;Ham and Kantzas, 2011).…”

“…Most laboratory studies that report relative permeability in coals measured by steady state or unsteady state core flooding methods derive a crossover point water saturation fraction (Sw) exceeding 0.5, which is usually interpreted as the coal being water wet or hydrophilic (Conway et al, 1995a;Durucan et al, 2013;Ham and Kantzas, 2011;Purl et al, 1991;Rahman and Khaksar, 2007;Shen et al, 2011). However, a problem with this standard approach is that it reports an average relative permeability for the core which assumes that the core has a uniform composition, homogenous wetting state and that the effects of capillary pressures are negligible.…”

Subsurface architecture of the Texas Orocline and its influence on in situ stresses in the overlying Surat Basin

“…The interaction of the stress tensor properties with pre-existing coal fractures determines which fractures are 'critically' stressed and hence more likely permeable , see review in Zoback 2007. Rahman and Khaksar (2007) raise the spectre of complex hydraulic fracture propagation and potential stimulation failures in complex in-situ stress environment, particularly in reverse stress regimes.…”