Coal seam gas associated water production in Queensland: actual vs predicted

Coal Seam Gas (CSG) development in Queensland is currently going through a transition from less than 300 billion cubic feet/year (∼315 PetaJoules/year (PJ/yr)) for domestic consumption to ∼1400 bcf/yr (nearly 1500 PJ/yr) by about 2019 driven by additional Liquid Natural Gas (LNG) export contracts. Prior to this ramp up in production, industry, government and academia have been forecasting not only gas but associated water production (produced water) for the various purposes of financial investment decisions and field development planning, prudent governance and regulatory planning, and estimation of potential environmental impacts for planning management, monitoring and mitigation strategies. During the course of resource development, prediction methodologies and model sophistication has varied greatly as more data becomes available and uncertainty is reduced. In Queensland, now that all 6 LNG trains are running and at various stages of ramping up to full production, there is a substantial and growing data inventory to history match numerical models and improve forward forecasting. We review the historical forecasting of CSG water production in Queensland leading up to the development and operation of CSG to LNG export, and compare that to the current actual produced volumes now that the projects have come on stream. The latest available measured produced water from CSG development (December 2016) equates to ∼60.5Giga Litres/year (GL/yr) with combined operator forecasts defining a peak projected to occur for about 10 years at 70–80 GL/yr. When this is converted to cumulative water volumes over the life of the industry (based on combined operator forecasts), just over 1700 GL of water is expected to ultimately be produced. Current estimates of water and salt production in Queensland are about 25% of those made by government and academia prior to the expansion of CSG to LNG export and ∼70% of the 2010–11 industry estimates. We show that this discrepancy can be attributable to a combination of the following factors: 1. Gas industry conservatism (over-estimation) driven by the bias to reduce project risk and achieve gas delivery targets;2. Government conservatism driven by a bias for prudent forecasting i.e. to assure that a credible worst case can still be managed within the regulatory framework;3. Academia conservatism driven by a bias for understanding worse case scenarios of environmental impact;4. The use of numerical models for basin scale impact assessment that do not take account of near-well multi-phase flow characteristics of saturation and relative permeability; and5. A systemic underestimation of the cumulative effects on depressurization of the coal resource where one operator's asset requires less water production to reach target reservoir pressures due to neighbouring operator production. This is mainly because each operator only has access to its own development plans

Recent advances in well-based monitoring of CO2 sequestration

Recent CO{sub 2} sequestration pilot projects have implemented novel approaches to well-based subsurface monitoring aimed at increasing the amount and quality of information available from boreholes. Some of the drivers for the establishment of new well-based technologies and methodologies arise from: (1) the need for data to assess physical and geochemical subsurface processes associated with CO{sub 2} emplacement; (2) the high cost of deep boreholes and need to maximize data yield from each; (3) need for increased temporal resolution to observe plume evolution; (4) a lack of established processes and technologies for integrated permanent sensors in the oil and gas industry; and (5) a lack of regulatory guidance concerning the amount, type, and duration of monitoring required for long-term performance confirmation of a CO{sub 2} storage site. In this paper we will examine some of the latest innovations in well-based monitoring and present examples of integrated monitoring programs

Hydrodynamics and membrane seal capacity

The impact of hydrodynamic groundwater movement on the capacity of seals is currently in debate. There is an extensive record of publication on seals analysis and a similar history on petroleum hydrodynamics yet little work addresses the links between the two. Understanding and quantifying the effects of hydrodynamic flow has important implications for calibrating commonly used seal capacity estimation techniques. These are often based on measurements such as shale gouge, clay smear or mercury porosimitry where membrane sealing is thought to occur. For standard membrane seal analysis, seal capacity is estimated by quantifying capillary pressure-related measurements and calibrating them with a large observational database of hydrocarbon column heights and measured buoyancy pressures. The seal capacity estimation process has historically been adjusted to account for a number of different generic trapping geometries. We define the characteristics of these geometries from a hydrodynamics viewpoint in order to fine-tune the seal capacity calibration process. From theoretical analyses of several simplified trapping geometries, it can be concluded that generally, the high pressure side of the seal should be used as the water pressure gradient with which to calculate buoyancy pressure. Secondly, trap geometries where hydrocarbon is reservoired on both sides of a fault are not useful for estimating across fault seal capacity

Keynote speech - Hydrodynamic constraints on fault seal analysis-linking capillary and fault reactivation processes

The overarching goal of fault zone analysis is to accurately estimate fault mechanical and hydraulic properties that may influence the connectivity either across a fault or along a fault and between reservoirs under variable stress conditions. Fault seal capacity is the term used to describe the ability of the fault to impede the migration of one or more fluid types under certain stress constraints. Academics and industry technologists have developed a number of techniques for assessing various physical characteristics of faults and these have often been grounded either in outcrop analogues or observations of faults in the subsurface thought to be either trapping hydrocarbons or showing evidence of breach. These techniques tend to be process specific, targeting fault rock strength, reactivation potential, across fault capillary seal capacity, or up-fault leakage potential. After examining these various components individually a holistic fault seal analysis can be assembled

Tectonic loading, sedimentation, and sea-level changes in the foreland basin of north-west Alberta and north-east British Columbia, Canada

By calculating mass accumulation rates for foreland basin sediments, the changing capacity of the basin can be monitored through time. It has often been assumed that there was a direct link between foreland basin sedimentation and tectonic deformation and lithospheric loading in the adjacent orogenic belt. The results of this study suggest that tectonic deformation is most likely associated with the changing capacity of the basin and the rate at which sediments accumulate within it. However, there appears to be no relation between tectonic deformation and the lithology of sediment which accumulates in the foreland basin. Instead, eustatic sea-level fluctuations appear to have significant control, through their impact on water depth, on the lithology of sediments accumulating in the foreland basin. These relations are evidenced by mass accumulation rates calculated for foreland basin strata in north-west Alberta and north-east British Columbia, Canada

Capillary seal capacity of faults under hydrodynamic conditions

Many fault bound traps are underfilled despite the top seal capacity being secure. The hydrocarbon sealing performance of faults themselves can be compromised either by mechanical or capillary process. Capillary process can be important either due to juxtaposition or to fine-grained clay or cataclastic material within the fault zone itself. There is debate about how important each of these mechanisms is over geological timescales of hydrocarbon trapping. Recent work has provided insights into fine-tuning capillary-related fault seal calibration methodologies. Over the last 15\ua0years, vigorous scientific debate with multiple published laboratory experiments and modelling studies has led some researchers and industry technologists to theorise that for water-wet conventional hydrocarbon reservoirs, the relative water permeability in the reservoir (towards the top of the hydrocarbon column) may become very small, but in practice never reach zero. While not advocating for either side in this debate, the importance of accounting for hydrodynamic conditions regardless of the capillary sealing mechanism is demonstrated. Additionally, it is noted that nonzero relative water permeability has implications on how a seal's capillary threshold pressure for the nonwetting hydrocarbon phase is estimated from field data. In the particular case where there are pressure differences between unproduced hydrocarbon reservoirs on either side of a fault, then the hydrocarbon saturation must be discontinuous across the fault. For hydrocarbon leakage to occur across the entire thickness of the fault zone, the hydrocarbon pressure must exceed the threshold pressure on the side of the fault zone with the highest formation water hydraulic head. This approach to estimating across-fault pressure difference will result in an improved calibration data set used for predrill estimation of capillary fault seal capacity

Regional-scale porosity and permeability variations, Peace River arch area, Alberta, Canada

This study examines the large-scale variability of porosity and permeability of the sedimentary rocks in the Phanerozoic succession in the Alberta part of the Peace River arch-area of the Western Canada sedimentary basin. The study is based on about 450,000 core analyses at approximately 22,000 wells in an area of more than 165,000 km2. Plug-scale porosity and permeability values are scaled up to the well scale by hydrostratigraphic unit, resulting in two sets of about 16,000 values each for porosity and permeability, unevenly distributed both areally and with depth. The permeability frequency distributions are lognormal for most of the units or parts of the units. The regional-scale variability of porosity and permeability is quite high, between 1 and 38% for porosity, and 0.001 md and 3 d for permeability. The clastic units of the foreland basin exhibit a relatively high correlation between permeability and porosity. Several areal trends and patterns are identified for groups of hydrostratigraphic units, patterns that change gradually from one group to another. It is hypothesized that the observed variability is caused by the dominance of the Peace River arch, carbonate deposition, or compaction at various times throughout the evolution of the basin. Based on the predominant controlling factor, the geological history can be divided into four periods: arch influence during the Early to Middle Devonian, reefal carbonate-deposition influence during the Middle to Late Devonian, passive margin influence during the Late Devonian to Middle Jurassic, and orogenic influence since the Middle Jurassic