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. 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. Southwest of the fairway, Fruitland coals are typically 20 to 40 ft thick and are considerably underpressured with vertical pressure gradients in some areas of less than 0.20 psi/ft. The low gradients are attributable to low permeabilities, low recharge rates along the southern rim of the basin, and hydraulic isolation from the fairway area.
This page pulls together technology-focused articles from various departments within JPT. Hydrocarbon processing and treating systems often require large and elaborate surface facilities. When operating in challenging locations, such as deep water or the Arctic, these systems can be expensive. Most underground gas-storage facilities are depleted reservoirs. What makes depleted reservoirs attractive is the presence of existing wells used to produce the reservoir, plus the geologic and engineering knowledge acquired during the development of the field. This paper uses a simulation model to evaluate and compare the thermal efficiency of five different completion design cases during the SAGD circulation phase in the Lloydminster formation in the Lindbergh area in Alberta, Canada. This paper covers the staged field-development methodology, including analysis and evaluation of various development concepts, that enabled the company to optimize both completion design and artificial-lift selection, reducing downtime and lowering operating costs by nearly 50%. The cost reduction per barrel of oil produced and the extension of sustainable production life by optimization have been two major areas of focus, but the investments in new technologies and recovery-improvement research have not received sufficient attention during the downturn. Machine-learning methods have gained tremendous attention in the last decade. The underlying idea behind machine learning is that computers can identify patterns and learn from data with minimal human intervention. This is not very different from the notion of automatic history matching. This paper discusses studies conducted on two California offshore fields that may be abandoned in the near future. These studies examined the feasibility of repurposing these fields for offshore gas storage by using their reservoir voidage and existing pipeline facilities. This paper investigates novel approaches to sour-gas treatment for use in the Middle East that are outside the common oil and gas market and compares them with traditional techniques. The operator piloted a new well-completion design combining inflow-control valves (ICVs) in the shallow reservoir and inflow-control devices (ICDs) in the deeper reservoir, both deployed in a water-injector well for the first time in the company’s experience. This paper shares experience gained in the Ashalchinskoye heavy-oil field with a two-wellhead SAGD modification.
JPT Technology Minute Poll: To Which of the Top Five UN Sustainability Development Goals Do You Think the Oil and Gas Industry Will Contribute the Most? Flaring and emissions challenges have recently made news headlines around the world. The goal of this article is to engage you with this important topic by presenting a selection of recent SPE papers which address these challenges through various approaches. Operators face a dilemma in balancing the need for mud weight (MW) to remain below the fracture gradient to avoid losses, while also providing sufficient density to block influxes into the well. JPT Technology Minute Poll: Which Technology Would You Choose for Offshore Compression?
Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
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.
Significantly different inputs are considered in deriving rock mass shear strength via Hoek-Brown Method (HBM) and Step-Path Method (SPM) approaches. The HBM cannot effectively assess the directional strength in rocks. Conversely, the key objective of the SPM is to consider the relative strength impact of the geological defects that are near co-aligned with part(s) or full length of critical failure paths through rock masses. Defect attributes considered in SPM are their orientation, relative occurrence, likelihood of cut-off by other defects, presence of intact rock and/or rock mass bridges between non cut-off defects and shear strength.
Where applicable by the structural conditions in the rock mass, the SPM strength may be 40-50% less than the equivalent HBM strength. However, SPM approach does require a more comprehensive understanding of the structural conditions in the rock mass and a greater analysis effort to develop the shear strength parameters.
In the SPM, the rock mechanics problem is partitioned into structural domains. Each domain is associated with a specific geological defect set that is approximately co-aligned with the anticipated critical failure path through this domain. General HBM conditions apply in those domains where no defect set is co-aligned with the failure path. In domains where the SPM is relevant, the conventional Hoek-Brown Geological Strength Index (GSI) chart values are adjusted for probability of occurrence, cut-off and length of bridges between non cut-off defects of those defect set(s) that impact rock mass strength outcomes.
The logic, methodology and step-by-step procedure for adjusting the Hoek-Brown GSI chart to derive SPM outcomes are described in detail. Example adjustments are presented to better illustrate the involved process.
The Hoek-Brown Method (HBM) for shear strength of rock masses was first published by Hoek and Brown (1980). HBM considers the intensity of rock mass ‘structure’ (blockiness) and ‘condition’ of geological defect surfaces. The same strength is computed for all directions through the rock mass.
Contrary to this initial HBM non-directional strength premise, failure paths are often structurally controlled and coincide with geological defects co-aligned with path directions. Some paths may be almost entirely defined by geological defects with only minor shearing through intact rock and/or rock mass ‘bridges’ between defects. To address HBM directional strength limitation, several authors revised the Geological Strength Index (GSI) chart to consider foliated rocks. These revisions are mostly qualitative; not quantitative.
In this study, we present regional in situ stress results analyzed based on geophysical logs and formation micro imager log data from two vertical boreholes in a carbonate oil and gas field to demonstrate how rock mechanical properties control in situ stress tensors. The carbonate reservoir exhibits highly heterogeneous rock properties depending on lithology. Horizontal principal stress magnitudes constrained by using borehole breakout width and the presence of drilling-induced tensile fractures show a wide variation in stress gradient. We note that the maximum horizontal principal stress gradient increases approximately linearly with Young’s modulus of layer, indicating that the heterogeneity in rock mechanical properties controls in situ stress magnitudes severely. Thus, a stiffer layer conveys a higher horizontal stress. Our results show that the influence of rock mechanical properties on in situ stress should be considered in field development.
During the last few decades, the substantial increase of in situ stress data has made a great advance in understanding the stress field of Earth’s crust. In general, crustal stress field shows partial variation at different scales of observation. At local scales, a deviation from regional pattern may be observed implicating the presence of other factors simultaneously affects crustal stress field. So far, local scale stress perturbations are believed to be the result of the presence of natural discontinuities (such as faults, fractures or bedding planes) and the mechanical heterogeneities in a rock formation. For example, there is ample evidence that the slip on faults and fractures induces stress release enough to perturb the stress state adjacent to them (Barton and Zoback, 1994; Shamir et al., 1992, Sahara et al., 2014, Rajabi et al., 2015, Lin et al., 2010). The influence of rock mechanical properties on stress state is especially pronounced in the heterogeneous rock formations such as carbonates, which has also been well documented in several previous studies (Teufel, 1991; Bruno and Winterstein, 1994; Wileveau et al., 2007). Understanding these perturbation mechanisms in local stress field is important for hydrocarbon reservoirs management.
In the present study, we had an opportunity to characterize the state of stress in a carbonate oil and gas field, onshore United Arab Emirates, where the reservoir is inherently heterogeneous in term of both geological structure and rock properties. The interbedding deposition characteristics of the reservoir and non-reservoir sections represent cyclical sedimentation, in which transgressions result in deposition of dense layers and regressions form the clean porous reservoir zones. It is worth to note that such depositional feature causes the great heterogeneity in physical and mechanical properties within reservoir. Our estimation of rock mechanical properties show that Young’s modulus significantly varies in a bimodal pattern approximately between 20 and 60 GPa. From the geomechanical point of view, carbonate formations in the study area can be separated into two main distinctive mechanical units, i.e., stiff and soft layers based on Young’s modulus (Fig. 1).
Bedded coal and iron ore deposits in Australia are usually hosted in complexly jointed, faulted or folded, highly anisotropic rock masses. In coal, these often comprise moderately strong siltstones and sandstones with weak coal seams, siltstones and shales. For iron ore, these comprise strong banded iron formations discretely interbedded with very weak shales. Slope failure mechanisms typically involve sliding along bedding (anisotropy) planes combined with joints or faults acting as release planes or forming step-path failure mechanisms.
Slope stability modelling techniques have evolved over the years and increased in complexity with continuous improvements in computing capability and available software. Less than 20 years ago, basic kinematic analysis was the primary means of designing large rock slopes. In the 2000s, the use of two-dimensional limit equilibrium analysis and numerical modelling rapidly increased with faster computing. As we approach the 2020s, three-dimensional limit equilibrium and finite element analysis software are readily available and offer a range of options to model the behavior of complex, anisotropic rock masses. The results obtained by these different modelling approaches, for example, isotropic vs. anisotropic, or 2D vs. 3D can vary significantly depending on the geological conditions.
This paper presents case studies from both open pit iron ore and coal mines that compare the factor of safety (FoS) obtained from 2D and 3D limit equilibrium modelling approaches. The case studies clearly show the limitations of 2D modelling when the rock mass being excavated is highly anisotropic in nature and when large-scale geological structures are present whose geometry cannot be adequately represented in plane strain. Results further indicate that modelling solely in 2D can lead to either the over-estimation or under-estimation of FoS, by failing to locate the section of slope with the lowest FoS or failing to adequately model the anisotropic conditions under which failure is likely to occur. The tools are now readily available to facilitate 3D modelling techniques alongside existing 2D techniques to complete a comprehensive review of slope stability. This will allow both the optimization of slope designs to be completed, and increase design reliability by identifying the sections of slope more susceptible to failure in true 3D space.
In 2014-15, income from sales and services from coal and iron ore mines in Australia was approximately $115 Billion (AUD), which accounted for approximately 80% of total mining and quarrying sector (ABS, 2016).
The Pilbara Region of Western Australia hosts the majority of economically extractable iron ore deposits in Australia. Hundreds of open cut mines are operated by major mining companies near the townships of Newman, Paraburdoo and Tom Price with single operations often having access to several individual pits in similar ground conditions. Due to the broad regional expanse of the operations, particularly in the iron ore sector, a very high extraction rate is achieved despite vertical development rates remaining relatively low (typically one to three benches or 10m to 30m per year in a single iron ore pit). Final pit depths or total rock slope heights range from less than 100m to 350m.
The Hunter Valley Region of New South Wales and the Bowen Basin Region in Queensland host the main coal deposits used for energy and steel manufacturing. Mining typically begins with an initial excavation, called a box cut, and then progresses down dip in a series of strips, with the coal closest to the surface extracted first. Pit geometry is dictated by equipment capabilities, the location of economic coal seams, and geotechnical constraints to achieve an acceptable design. Individual bench heights typically do not exceed 60m and overall excavated slope heights rarely exceed 150m.
A full-field dynamic simulation model has traditionally been seen as the benchmark for assimilating all available static and dynamic data to develop robust production forecasts. Santos’ experience modelling the Walloon Coal Measures in its Surat Basin acreage has shown that the performance of individual wells producing from this CSG reservoir is governed by reservoir variability at a fine-scale. This presents a fundamental challenge in developing full-field dynamic models that can accurately describe and predict production performance down to the scale of individual coal seams.
Current Queensland CSG projects have focussed on the most prospective acreage, however as subsequent developments move to more marginal areas a greater understanding of the subsurface will be required for optimum development. The target formations will increase in geological complexity, such as Santos’ Surat Basin acreage on the edge of the CSG fairway. Here wells produce from a greater number of distinct coal reservoir units, and how these reservoir units are structured and relate to each other governs reservoir connectivity and defines long-term production performance. Each reservoir unit is comprised of multiple coal plies, all with their own unique maceral distribution and cleating characteristics. These fine-scale properties define the reservoir's dynamic behaviour, and can be impossible to upscale such that these characteristics are preserved at a coarse scale. Consequently, accurately modelling individual well performance will require a fine-scale model to capture and characterise this variability.
In development areas where the quantity and quality of reservoir data gathered from exploration and appraisal is sparsely populated, these fine-scale models will need to be populated geostatistically. Without model-scale appropriate control data from production and pressure measurement in the development wells to provide constraints however, a probabilistic model will not accurately define fine-scale behaviour of specific reservoir units. These data requirements can help shape the appraisal scope for new areas and define an appropriate level of surveillance for producing assets.
Traditional full-field dynamic modelling has fundamental limitations for interrogating complex unconventional CSG reservoirs at a fine scale. Because of this, alternative workflows are required to answer the subsurface questions necessary to develop CSG assets such as the Surat Basin effectively. This paper details a selection of workflows explored to address this pragmatically, as well as their limitations and associated data requirements. This will also assist in identifying data gaps needed for optimum reservoir management and to aid in the development of these challenging CSG reservoirs.