Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. For a long time, the Fruitland formation coals were recognized only as a source of gas for adjacent sandstones. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Coals in the fairway typically have low ash and high vitrinite contents, resulting in large gas storage capacities and excellent permeabilities of 10 md from well-developed cleat systems.
The Cooper Basin of Australia is challenged by strike-slip to reverse stress regimes, adversely affecting hydraulic fracturing treatments. In drilling, the high deviatory stress conditions increase borehole breakout, affect log acquisition and impact cementing job quality. The non-favourable stress conditions in conjunction with natural fracturing result in: complex fracturing (with shear and sub-vertical components); high near-wellbore pressure loss (NWBPL) values; and stimulation of lower permeability, low modulus intervals (e.g., carbonaceous shales, interbedded coals) in preference to the targeted and higher modulus, tight-gas sandstones. Typically, vertical wells have been employed in past completions of the Cooper Basin as well as in the offsetting areas to the case study in the Windorah Trough, Southwest Queensland.
We will present the results from two case study wells offsetting a previous vertical well where well trajectory, completion and fracture design changes were employed in an ongoing experiment to improve job execution for Patchawarra tight gas reservoir treatments in the Cooper Basin. The two wells were directionally deviated at 31° and 25° final inclinations from vertical with azimuth <10 deg from the maximum horizontal stress direction, as determined from offsetting well data. To better define sections with limited, poor or missing log data (because of difficult hole conditions), drilling data, logging while drilling (LWD) gamma ray data, openhole conventional and dipole sonic logs, along with prior 1D stress data were used with a machine learning model to improve stress profiling and reservoir characterization. Next, perforations were shot 0 and 180° phased along the wellbore and initial fluid viscosity was increased to better align the hydraulic fracture and reduce NWBPL, respectively. Finally, diagnostic fracture injection tests (DFIT) were performed in sections of varying moduli below and in the zone of interest in order to verify the horizontal strains and calibrate the final 1D stress profile prior to stimulating both wells.
The improved well and perforation alignment to the maximum horizontal stress direction has improved reservoir connection, lowered NWBPL in some cases, and in some cases improved fracture containment. Decreasing injection rates and minimizing perforated intervals has improved targeting of desired intervals; however, overall fracture widths remain low and continue to be sensitive to proppant sizing and concentrations with several screen outs experienced. This experimentation has resulted in short-term production improvements in the wells using 4- and 3-stage treatments relative to the offsetting vertical well where a 5-stage treatment was executed.
Hydraulic fracture stimulation of low permeability source rock-reservoirs is increasing in the industry and low-permeability, deeply buried coals, "Deep Coals," represent an underdeveloped resource in the Cooper Basin of South Australia. Numerous treatments have been performed with overall technical success but varied productivity. Thus, it was important to understand the potential hydraulic fracture conductivity in the Permian Deep Coal play by evaluating the key treatment variables affecting post-stimulation results. Proppant conductivity tests were conducted on samples from two preserved Deep Coal cores of differing thermal maturity under laboratory conditions, replicating reservoir conditions. Varying concentrations and mesh sizes of lightweight ceramic (LWP) and sand proppants were tested at 250 F. All tests were subject to closure stresses observed in the field, ranging from 2,000 psi to 10,000 psi, using representative hydraulic fracturing fluids. Results revealed a significant conductivity difference between the two coal thermal ranks due to variation in mechanical properties Varying proppant concentration tests revealed that effective conductivity at higher stresses occurs within a narrow window. This window is a balance between insufficiently low concentration resulting in significant conductivity loss, and excessive, nonlinear conductivity gains in higher concentrations. Results from these studies are integrated into a hydraulic fracture and reservoir stimulation modelling software to upscale the observed results versus the laboratory data. Finally, laboratory results helped explain trends for success in stimulation design based on observed post-frac, flow rates.
Despite decades of numerical, analytical and experimental researches, sand production remains a significant operational challenge in petroleum industry. Amongst all techniques, analytical solutions have gained more popularity in industry applications because the numerical analysis is time consuming; computationally demanding and solutions are unstable in many instances. Analytical solutions on the other hand are yet to evolve to represent the rock behaviour more accurately.
We therefore developed a new set of closed-form solutions for poro-elastoplasticity with strain softening behaviour to predict stress-strain distributions around the borehole. A set of hollow cylinder experiments was then conducted under different compression scenarios and 3D X-Ray Computed Tomography was performed to analyse the internal structural damage. The results of the proposed analytical solutions were compared with the experimental results and good agreement between the model prediction and experimental data was observed. The model performance was then tested by analysing the onset of sand production in a well drilled in Bohai Bay in Northeast of China. Acoustic and density log along with core data were used to provide the input parameters for the proposed analytical model in order to predict the potential sanding in this well. The proposed solution predicted the development of a significant plastic zone thus confirming sand production observed by today sanding issue in this well.
Baharuddin, Saira Bannu (Petroliam Nasional Berhad, PETRONAS) | Khair, Hani Abul (Petroliam Nasional Berhad, PETRONAS) | Bekti, Reza Amarullah (CGG) | Ali, Amita Mohd (Petroliam Nasional Berhad, PETRONAS) | Kantaatmadja, Budi (Petroliam Nasional Berhad, PETRONAS) | Som, Mohd Rapi Muhammad (Petroliam Nasional Berhad, PETRONAS) | Sedaralit, Faizal (Petroliam Nasional Berhad, PETRONAS)
Bioturbated zones are frequently bypassed by oil and gas operating companies during perforation due to the perception that they are nonproductive. We analysed data from wells in four fields in the Sarawak Basin, Malaysia, for selected bioturbated zones. The study included thin section, probe-permeameter, petrophysical, and routine core analysis. A bioturbation index classification scheme was established to allow semi-quantitative ranking for each foot of core. In the current study, we introduce a simulation script to predict lithofacies types at well locations based on input from bioturbation intensity algorithm (Ali et al., 2016), this script can be used for application on shallow marine field within Malaysia. We also used post stack seismic inversion for acoustic impedance and it proved to be a key approach to enhance the ability of predicting rock properties between wells. We generated a seismic derived lithofacies which provided the best estimate of lithofacies distribution between wells even though a well derived lithofacies had higher resolution. We calculated STOIIP using input from seismic lithofacies and porosity, and the results showed more accurate estimate of hydrocarbon in place compared with statistical approaches. Thus, the current seismic lithofacies methodology can be used for static model building and STOIIP calculation in shallow marine environments.
ABSTRACT: The city of Sydney (Australia) is currently undergoing a major infrastructure construction boom, with numerous rail and road tunnels currently under construction. This paper presents the DFN modelling undertaken as part of the design process for the Parramatta and Wattle (PW) Caverns of the M4East project.
The PW caverns are expected to be excavated in fresh Hawkesbury Sandstone. At the study site the primary discontinuities controlling block formation are expected to be joints, bedding planes and bedding plane shears. The DFN modelling of this study has been built to be representative of these types of structures. This paper presents the necessary input parameters for the modelling, derivation of these parameters along with the model generation process. Of particular importance for engineering applications is the development of realistic DFN models and validation of the simulated fracture network. The simulated fracture networks were shown in this instance to be a good fit to the measured field data.
Multiple realizations of the model were generated, with a stability analysis carried out on each. The stability analyses were used to develop the unstable block volume distribution and identify the maximum likely block volume for the crown and sidewalls of the cavern. Large stable blocks were found to occur between the parallel caverns, where the tunnel sidewalls form two boundaries.
Excavation to date has provided field verification of the modelling, with the shape and dimensions of the blocks within the predicted range.
ABSTRACT: According to the studies on tight gas reservoirs, liquid CO2 (L- CO2) is much superior in hydraulic fracturing compared to conventional fracturing fluids. However, the applicability of this technique for hydraulic fracturing of coal seams has been hindered due to the lack of understanding. This paper investigates the superiority of L-CO2 as a fracturing fluid for coal seam gas extraction, in terms of break-down pressure and acoustic emission (AE) energy release during fracture propagation. The results reveal that L-CO2 induced break-down pressure is around 19.6% lesser than the water induced break-down pressure, whereas the time taken to break-down is 59.3% higher for L-CO2 compared to water. Importantly, due to the low compressibility, water injection pressure showed an exponential pressure development closer to the break-down, resulting a higher break-down pressure within a short time period. Conversely, the highly compressible L-CO2 exerted only a gradual increment in pressure in the sample over a considerable time, which caused a more controllable fracturing process. The observed AE suggests that the ability of low viscous L-CO2 to penetrate through the tiny pores in the coal mass has the potential to create a stable and dense fracture network, instead of the uncontrolled unstable sudden failure occurred under the water based fracturing. This well-developed fracture network can significantly enhance the rock mass permeability and the reservoir gas extraction. Overall, it can be concluded that the combined characteristics of L-CO2 (high compressibility, low viscosity) lead more controllable and effective coal seam hydraulic fracturing process compared with the water based fracturing.
Hydraulic fracturing is one of the well-established well-stimulation methods, which has been used for enhanced coal bed methane extraction (ECBM), over last few decades. The process involves mechanically fracturing of the reservoir by injecting a pressurized fluid into the rock formation through vertical and horizontal wellbores drilled in the reservoir. A mechanically induced fracture network, as provided by this process, is necessary to deliver an economic gas production, especially from low permeable reservoirs like coal. The efficiency of the fracturing process depends on the characteristics of the induced fracture network, which ultimately governs the permeability enhancement of the formation. Thus, the induced fracture network should have a large surface contact area between fractures and the reservoir and a high fracture interconnectivity, in order to provide an easy pathway for the gas to move towards the wellbore (King, 2010).
ABSTRACT: We use a direct shear apparatus with embedded ultrasonic transducers to correlate the macroscopic frictional response with the microscopic contact processes occurring between two blocks of shaly sandstone. At constant normal load, we observe stable sliding at low velocities and oscillatory stick-slip at high velocities. For slow sliding, or during the stick phase of the stick-slip cycle, variations in the transmitted compressional P-wave amplitude show the existence of healing processes occurring at the joint, e.g. associated to the increase in contact area with contact time. Moreover, the transmitted shear S-wave amplitude is sensitive to other processes with opposite velocity dependence. The interplay between these processes, displaying velocity weakening (VW) and velocity strengthening (VS) respectively, explain the observed maximum in the steady state shear response as function of shearing rate. We also observe that the wave velocity is sensitive to gouge formation at the joint. This mechanism is induced by sliding and enhanced with shearing rate. At low shearing rates, in the VS region, small amounts of debris are formed, slightly strengthening the joint. At high shearing rates, in the VW region, the wear material significantly increases the mean separation between the two surfaces, resulting in a weaker joint.
Understanding contact scale physical processes is necessary to interpret in detail the frictional behavior of natural and simulated faults. The extent of these processes, such us plastic creep, gouge comminution or capillary condensation, directly determine the state of contact and overall strength of the fault, either by affecting the real contact area or the local strength of contact zones. Geophysical imaging of ultrasonic waves interacting with rock joints have been used as a non-destructive technique that measures the state of contact and real contact area (Kendall and Tabor, 1971; Nagata et al., 2008, 2012; Hedayat, 2013; Hedayat et al., 2014a-d; Gheibi and Hedayat, 2018a). Ultrasonic waves transmit through the points in contact and reflect at the air void spaces and in this way they can provide an indirect measure of the state of contact within the zone of measurement. Thus, the intensity of the wave transmitted through the asperities in contact can be a measure of the stiffness of the asperities and the real contact area.
Shear experiments conducted on gypsum rock joints (Hedayat et al., 2012; 2013) and Indiana limestone rock joints (Hedayat et al., 2014a, 2018; Hedayat and Walton, 2017) show that precursors in the form of maximum amplitude of ultrasonic waves appear before reaching the static shear strength of contacting surfaces. Based on the variations in the amplitude of transmitted and reflected ultrasonic waves, Hedayat et al. (2018) identified two major processes occurring during both frictional sliding and stick-slip oscillations, as follows: (a) interseismic phase and (b) preseismic phase. The interseismic phase was associated with small local slip rate and increasing ultrasonic transmission along the contact surfaces while the rock joint was locked. Such increase in the ultrasonic transmission represented an increase in the real (true) area of contact. The onset of preseismic phase was associated with the appearance of precursors for different regions of the rock joint.
Shirole, Deepanshu (Colorado School of Mines) | Walton, Gabriel (Colorado School of Mines) | Ostrovsky, A. Lev (University of Colorado) | Hossein, Masoumi (Monash University) | Hedayat, Ahmadreza (Colorado School of Mines)
ABSTRACT: It is a well-established fact that the ultimate failure of rocks is preceded by the initiation, growth, and coalescence of micro-cracks. A plethora of techniques have been developed over the years for the characterization of the different stages of micro-cracking in rocks, but an objective approach for monitoring damage evolution in rocks has still not been fully established. In this paper, a new non-linear ultrasonic testing approach, the Scaling Subtraction Method (SSM), has been used to evaluate its potential to detect the signatures of the mechanical changes that accompanies a rock at different levels of damage. This approach is implemented based on the hypothesis that non-linear components of ultrasonic waves have increased sensitivity to damage. Firstly, aluminium, Gosford sandstone and Lyon's sandstone were characterized and their inherent non-linearity was established using a SSM non-linear indicator θ. Then, a Gosford sandstone specimen was damaged under uniaxial compressive step-loading and ultrasonic measurements were performed at each loading step. The non-linear indicator θ was calculated as the specimens were progressively damaged, and in such a way, the efficiency of SSM technique in capturing damage signatures was evaluated. The study concluded that the elastic non-linearity in a specimen, either due to its inherent micro-structure or due to damage, can be successfully quantified using the non-linear SSM indicator (θ).
Yielding of rocks at stresses well below the laboratory ultimate compressive strength (UCS) is associated with the damage induced in the rocks due to the initiation and coalescence of micro-cracks. The stress corresponding to the systematic initiation of the cracks is defined as the Crack Initiation (CI) threshold, while the stress threshold at which the accumulated cracks in the rock begin to coalesce is termed as Crack Damage (CD) (Diederichs and Martin, 2010; Ghazvinian, 2015). Characterization of these damage thresholds is vital for a precise prediction of the rock behavior during the excavation of underground structures. A number of approaches have been developed over the past years for characterizing these damage thresholds, but an objective approach for determination of an early damage (CI) evolution is still difficult at best (Nicksiar and Martin, 2012; Meyer, 2018). In this study, a non-linear ultrasonic testing (NLUT) method has been used to evaluate its capability to detect the signatures of different stages of microcracking in a uniaxially loaded (shaly) Gosford sandstone specimen.
Zhang, Wenping (China University of Petroleum-Beijing) | Li, Gensheng (China University of Petroleum-Beijing) | Huang, Zhongwei (China University of Petroleum-Beijing) | Song, Xianzhi (China University of Petroleum-Beijing) | Mao, Sheng (China University of Petroleum-Beijing) | Dai, Xianwei (China University of Petroleum-Beijing) | Guo, Zhaoquan (China University of Petroleum-Beijing) | Cheng, Zhen (China University of Petroleum-Beijing)
ABSTRACT: Temperature and fluid affect the rock properties is an unavoidable problem in drilling engineering. The objective of this study is to separate the effect of temperature and fluid medium on hard sandstone drilling parameters, which include the weight of bit (WOB), torque and mechanical specific energy (MSE). A series of rock drilling experiments was carried out. The results was very interesting that liquid nitrogen (LN2) cause the sandstone more difficult to drill than air and water, which is contrary to the view that the differential temperature between low temperature fluid and the rock enhance the rock failure. LN2 caused the average MSE to be increased by about 20.64%, water caused the average MSE to be reduced by about 42.66%, compared with dry drilling. From the results, it can be concluded that the temperature has no significant effect on hard sandstone drilling parameters and fluid medium type affect the parameters remarkably in the range of 20-300°C. This phenomena maybe attribute to that water caused the surface free energy of new cuttings surface reduced and LN2 caused the surface energy increased compared with air.
The effect of temperature and fluid medium on rock's failure and deformation is important in many engineering applications such as radioactive waste disposal, freezing and thawing cycles of rock, underground resource development, geotechnical engineering, rock weathering, and so on. Temperature and fluid affect the rock properties is an unavoidable problem in drilling engineering. For instance, underbalanced drilling has been widely applied and researched by virtue of high drilling rate (George et al., 1956; Cppper et al., 1977; Negrao et al., 1997; Fattah et al., 2011). Through field verification, the rate of gas drilling is usually over 10 times higher than conventional drilling with liquid fluid. The effect of bottom pressure on rock failure seems to explain the extremely high rate of penetration in drilling (Sheffield and Sitzman, 1985), but the effect of temperature and medium on rock's failure seemed also can’t be neglected (Li et al., 2014). Drilling is a complex physical and chemical process involving multi-field and multi-media coupling, such as mechanical field, temperature field, flow field, etc. The thermal impact assisted rock failure has been a hot topic in the past decades. Some scholars (Zhang et al.,2014; Guo and Ghalambor, 2002) believe that the temperature difference between the gas and the formation causes tensile stress in the rock, promote the rock fragmentation in gas drilling. As the differential thermal expansion of mineral grains subjected to elevated temperature induced microcracks, which decrease drillability and enhance the penetration rate (Karfakis, 1985). But the research result of Zhou (2003) indicated that the effect of formation temperature on the properties of reservoir rocks of this area should be neglected. Due to underground invisibility and environmental complexity, the effect of temperature on rock failure at the well bottom is still not fully understood.