Hon Chung Lau

Production Technology Challenges of Tight and Shale Gas Production in China

Natural gas production from tight and shale gas reservoirs is becoming increasingly important in China as the country shifts from coal-based energy to cleaner energy sources. Recent Chinese sources have estimated that the gas-in-place resources from tight and shale gas reservoirs in China are at least 12 and 31 Tcm, respectively1. In 2008, annual production from tight gas reached 20 Bcm, about 23% of natural gas production in China1. Commercial production from shale gas reservoirs is yet to begin, but is expected to grow rapidly in the future. This paper gives an overview of the production technology challenges of tight and shale gas production in China. Based on a review of the published literature and their own observations, the authors have identified a number of key production technologies that are relevant and can potentially make significant impact on tight and shale gas production in China. They include, among others, management of H2S risks, sourcing and disposal of water for hydraulic fracturing, pad drilling and completion, incorporation of geomechanics in well design and reservoir modeling, non-formation damaging fracturing fluids, and improved multi-stage fracturing techniques. This paper should be of particular interest to subsurface engineers, scientists and managers who are involved in tight and shale gas production in China. It will also be of interest to researchers in universities and research institutes who are interested to develop these technologies to unlock unconventional gas resources in China.

Laboratory development and field application of a novel water-based drill-in fluid for geopressured horizontal wells

Research has identified a novel water-based drill-in fluid for drilling and completing geopressured horizontal wells. This fluid has a unique combination of properties which make it especially suitable for geopressured applications. They include the use of calcium and/or zinc bromide as a base brine, minimal concentration of calcium carbonate as bridging material, low plastic viscosity, tight fluid loss control, good filter cake properties, and excellent return permeability. This drill-in fluid has been used successfully to drill a 1,200 foot production interval, 4.75 inch diameter wellbore in the Gulf of Mexico with a system weight of 13.2 1bm/gal, bottom hole temperature of 185° F., and a 1400 to 1700 psi overbalance. The system functioned very well in both the drilling and completion operations. Fluid rheology was easily maintainable and the hole conditions were excellent without torque or drag problems. Initial production data suggests that the well is producing at expected rates with low drawdown pressure.

Laboratory Development and Field Testing of Succinoglycan as a Fluid-Loss-Control Fluid

Research has shown that the biopolymer succinoglycan possesses a unique combination of desirable properties for fluid-loss control, including ease of mixing; cleanness; shear-thinning rheology; temperature-insensitive viscosity below its transition temperature, T[sub m]; and adjustable T[sub m] over a wide range of temperatures. Because succinoglycan is a viscous fluid, it relies solely on viscosity to reduce fluid loss. It does not form hard-to-remove filter cake that can cause considerable formation damage. On the basis of these findings, the author used succinoglycan successfully as a fluid-loss pill before and/or after gravel packing in > 100 offshore wells. Calculations based on laboratory-measured rheology and field experience have shown succinoglycan to be effective in situations where hydroxyethyl cellulose (HEC) is not. Even fluid loss > 40 bbl/hr was reduced to several bbl/hr after application of a properly designed succinoglycan pill. Most wells experienced no production problem after completion.

Laboratory Development and Field Application of a Novel Water-Based Drill-In Fluid for Geopressured Horizontal Wells

Research has identified a novel water-based drill-in fluid for drilling and completing geopressured horizontal wells. This fluid has a unique combination of properties which make it especially suitable for geopressured applications. They include the use of calcium and/or zinc bromide as a base brine, minimal concentration of calcium carbonate as bridging material, low plastic viscosity, tight fluid loss control, good filter cake properties, and excellent return permeability. This drill-in fluid has been used successfully to drill a 1,200 foot production interval, 4.75 inch diameter wellbore in the Gulf of Mexico with a system weight of 13.2 lbm/gal, bottom hole temperature of 185{degrees} F., and a 1400 to 1700 psi overbalance. The system functioned very well in both the drilling and completion operations. Fluid rheology was easily maintainable and the hole conditions were excellent without torque or drag problems. Initial production data suggests that the well is producing at expected rates with low drawdown pressure.

Detailed Characterization of a Multilayered Coalbed Methane Field Using High-Resolution Sequence Stratigraphy: Examples from the Surat Basin in Australia

The Walloon Coal Measure (WCM) in the Surat Basin in Australia consists of coal-rich mire and a fine-grained meandering fluvial system. The main gas producing targets of WCM are numerous thin coal plies within six coal members with frequent pinching outs, splitting and merging. The geology is stratigraphically complex making correlations of individual coal plies difficult. Consequently, previous geological studies have been mostly based on coal members instead of individual coal plies resulting in inadequate description of the heterogeneity of the coal deposit. To remedy this situation, we proposed a workflow using high-resolution sequence stratigraphy to build an isochronic stratigraphy framework of sublayers and coal plies by utilizing all available data from cores and logs. The key methodology was to identify single fining-upwards cycles with coal, clay or siltstone at the top and sandstone at the base. Then similarity analysis on the cycles was used to identify aggradation, progradation or retrogradation of fluvial facies sequence between adjacent wells. Log density cutoff was used to identify coal, shaly coal, shale, sandstone and siltstone from the whole Walloon fluvial system. Reservoir parameters including gas, ash, moisture content, density, and permeability versus depth were correlated taking into consideration depth shift, regional core data and lithology in different members. All of the above were integrated into a ply-based geomodel which was used to identify highly concentrated, overlapping, continuous plies that are potential sweet pots for field development. Our intent is to provide analogue information and understanding for the coal seam distribution in the green field development of the Surat Basin. This methodology was applied to WCM to perform division and correlation of 20 sub-layers and 125 single plies with thickness ranging from 0.3-1.4 m. Coal distribution area versus thickness relationship was generated to analyze the variogram range used for some key properties, especially density and net-to-gross, and to investigate the impact of coal continuity on well spacing. Five micro-facies in fluvial system were used to describe the distribution of coal properties, impact of coal architecture and heterogeneity. Several potential sweet spots for field development were identified. With proper upscaling, this high-resolution ply-based model can be used in reservoir simulation to forecast production and calculate estimated ultimate recovery (EUR). This methodology has been applied to three coalbed methane (CBM) fields in the Surat Basin in Australia. It is novel in applying high-resolution sequence stratigraphy used in geomodel building of convention oil and gas reservoirs to CBM characterization. It has resulted in a better understanding of the complex depositional character of the WCM and consequently more accurate determination of potential sweet spots, production forecast and EUR calculation.