Alireza Salmachi

Cross-formational flow of water into coalbed methane reservoirs: controls on relative permeability curve shape and production profile

AbstractCoalbed methane (CBM) wells tend to produce large volumes of water, especially when there is hydraulic connectivity between coalbed and nearby formations. Cross-formational flow between producing coal and adjacent formations can have significant production and environmental implications, affecting economic viability of production from these shallow reservoirs. Such flows can also affect how much gas can be removed from a coalbed prior to mining and thus can have implications for methane control in mining as well. The aim of this paper is to investigate the impact of water flow from an external source into coalbed on production performance and also on reservoir variables including cleat porosity and relative permeability curves derived from production data analysis. A reservoir model is constructed to investigate the production performance of a CBM well when cross-formational flow is present between the coalbed and the overlying formation. Results show that cleat porosity calculated by analysis of production data can be more than one order of magnitude higher than actual cleat porosity. Due to hydraulic connectivity, water saturation within coalbed does not considerably change for a period of time, and hence, the peak of gas production is delayed. Upon depletion of the overlying formation, water saturation in coalbed quickly decreases. Rapid decline of water saturation in the coalbed corresponds to a sharp increase in gas production. As an important consequence, when cross-flow is present, gas and water relative permeability curves, derived from simulated production data, have distinctive features compared to the initial relative permeability curves. In the case of cross-flow, signatures of relative permeability curves are concave downward and low gas permeability for a range of water saturation, followed by rapid increase afterward for water and gas, respectively. The results and analyses presented in this work can help to assess the impact of cross-formational flow on reservoir variables derived from production data analysis and can also contribute to identifying hydraulic connectivity between coalbed and adjacent formations.

Fluid flow characteristics of Bandanna Coal Formation: a case study from the Fairview Field, eastern Australia

ABSTRACT Fluid flow characteristics of cleat systems in coalbed methane reservoirs are crucial in reservoir management and field development plans. This paper aims to evaluate the cleat system properties including cleat porosity, permeability, and aperture as well as the impact of permeability growth on production performance in the Bandanna Coal Formation of the Fairview Field, eastern Queensland. Owing to the presence of bad hole conditions and poor core recovery of the coal intervals, the petrophysical well logs and laboratory measurements cannot be used as a source of information for this purpose. Hence, a new approach is employed that utilises early water production data to measure water in place and absolute permeability of the coal. In addition, micro-computed tomography (CT) scan method is used to investigate the cleat system that is preserved in a core sample and results are compared with the ones obtained by analysis of production data. Cleat system evaluation by analysis of production data and micro-CT scan technique provides a comprehensive approach that brings confidence in measurements and helps to obtain cleat properties at the sufficient scale for reservoir engineering purposes. The necessary information including production data and core samples are collected from a dewatering well and the nearby observation well in the study area. Analysis of early water production data (single-phase flow) indicates that coal permeability is 189 mD and the average cleat porosity is approximately 5%. High cleat porosity describes the large volume of water produced over the life of the study well. The 3D model of the fossilised cleat system constructed by the micro-CT scan method reveals that coal is well-cleated and cleat spacing and mean cleat aperture are 4 and 0.136 mm, respectively. The average cleat porosity that is measured by the micro-CT scan method is 5.7%, which is fairly close to the cleat porosity measured by analysis of production data. Production data analysis indicates that effective permeability to gas starts to grow at the midlife of the well and it strongly controls the shape of the production profile. The results of this study help in future field development and infill drilling programs in the Fairview Field and provide important insights into cleat system of Bandanna Coal Formation.

A Semi-analytical Model for Pressure-Dependent Permeability of Tight Sandstone Reservoirs

In tight gas reservoirs, permeability is pressure dependent owing to pore pressure reduction during the life of the reservoir. Empirical models are commonly used to describe pressure-dependent permeability. In this paper, it was discussed a number of issues which centered around tight sandstone pressure-dependent permeability experiment, first to apply core aging on permeability test and then to develop a new semi-analytical model to predict permeability. In tight sandstone permeability test experiment, the microinterstice between core and sleeves resulted in over estimation of dependency of permeability on pressure. Then, a new semi-analytical model was developed to identify the relation between permeability and fluid pressure in tight sandstone, which indicates there is a linear relation between pore pressure changes and the inverse of permeability to a constant power. Pressure-dependent permeability of 8 tight sandstone core samples from Ordos Basin, China, was obtained using the modified procedure, and results were perfectly matched with the proposed model. Meanwhile, the semi-analytical model was also verified by pressure-dependent permeability of 16 cores in the literature and experiment results of these 24 cores were matched by empirical models and the semi-analytical model. Compared with regression result of commonly used empirical models, the semi-analytical model outperforms the current empirical models on 8 cores from our experiment and 16 cores from the literature. The model verification also indicates that the semi-theoretical model can match the pressure-dependent permeability of different rock types. In addition, the permeability performance under reservoir condition is discussed, which is divided into two stages. In most tight gas reservoirs, the permeability performance during production is located in stage II. The evaluation result with proposed experiment procedure and the stress condition in stage II will reduce permeability sensitivity to stress.

Drilling data of deep coal seams of the Cooper Basin: analysis and lessons learned

Deep (>4920 ft; >1500 m) coal seams of the Cooper Basin accommodate large amounts of natural gas; however, permeability of this unconventional resource is low and reservoir stimulation in prospective coal intervals is essential to achieve commercial production. This paper aims to analyse drilling data of deep coal seams of the Cooper Basin in South Australia. Drilling data obtained from mud logs are utilised to construct a drillability index (DI), in which rate of penetration is normalised by drilling factors, making DI more sensitive to coal rock strength. Analysis of DI and gas show information provides a preliminary screening tool for studying prospective deep coal seams, before performing in-depth reservoir characterisation and production tests. The decline in DI with depth is attributed to a compaction effect that makes deeper coal seams more difficult to drill through compared with shallow seams. The existence of a fracture network can reduce coal rock strength and consequently DI may increase. The increase in DI may be indirectly related to fluid flow characteristics of the coal seam helping in identifying prospective coal intervals. The DI is also affected by other factors and, hence, should be used in combination with reservoir information to yield conclusive indications. Gas show information and DI results were utilised to indicate the effectiveness of dewatering operation and hydraulic fracture confinement in the wells drilled in the Klebb area located in the Weena Trough.

Psyllium husk performance in drilling fluid at elevated temperature and pressure conditions

High performance water-based drilling fluid alternatives that meet performance objectives with minimal environmental impact must continually be developed. Drilling fluid performance is dependent on fluid characteristics, and among those most critical are viscosity and filtration. One avenue to improve drilling fluid performance is through enhancement by use of potent, water-soluble natural polymers. Psyllium husk powder is an environmentally friendly natural polymer derived from ground-up surfaces of psyllium seeds (Plantago ovata). When in contact with water, psyllium husk powder forms a gel-like, extraordinarily viscous substance at very low concentrations. It was previously shown that pure psyllium husk is an excellent viscosity and filtration agent for water-based drilling fluid under standard conditions. Psyllium husk can also be used as a clay-extender to enhance viscosity and filtration performance of bentonite mud; however, further laboratory testing of this performance enhancement under elevated temperatures and pressures is required. Extensive laboratory experiments were therefore conducted to test husk performance in bentonite mud under such conditions. An electronic rheometer and a temperature and pressure adjustable API filter press were used to evaluate viscoelastic and filtration mud characteristics respectively. Concentrations of 0.05–0.4% husk with 5% bentonite were tested at 25−120°C under 1500 psi. An optimal husk concentration of 0.1% was determined, increasing bentonite viscosity and yield point by up to 46.9% and 68.1% respectively. Filtrate loss rate and filtration cake thickness were reduced by up to 25.8% and 35.3% respectively. The optimal concentration was useable up to 70°C (~2800 m) before deflocculating was required.

Effect of Volcanic Intrusions and Mineral Matters on Desorption Characteristics of Coals (Case Study)

In this study, coal seams properties in two coal core wells are studied to identify dominant parameters controlling desorption characteristics of coals. Available published data from desorption canister tests including sorption time and gas content (lost gas, desorbed gas, and residual gas) are employed. Proximate analysis data assists in coal characterization and data from high pressure adsorption tests are used to investigate the methane adsorption on coal as a function of pressure. For fracture and cleat analysis, gamma ray, density, and acoustic image logs are used. All data and analysis combined with regional geology assist to study desorption properties of different coal seams in these two wells. Kalbar-1 and Peebs-1 are the two core wells in this study. Entirely different patterns (gas content versus depth) are observed which can be explained by their different geological setting. A major volcanic intrusion of approximately 60m in thickness and a few minor intrusions in the area explain abnormally high gas content of shallow coal seams. The methane Langmuir adsorption isotherm for shallow coals (composite sample) is steep and has higher gas adsorption capacity compared to other seams. The shallow coal seams have been cooked by volcanic intrusions and have higher than expected gas content. For Peebs-1, the composite plot of gas content, sorption time, and ash content combined with gamma ray, density, and acoustic image logs provides a useful set to study desorption properties of coal seams. The fracture and cleat analysis reveals that low sorption time generally belongs to coal seams with higher cleat and fracture density. The existence of open cleats and fractures might facilitate gas release from coal matrix. The inverse correlation observed between sorption time and ash content while maceral composition is fairly similar suggests that desorption properties might be controlled by mineral matters in this well.