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At present, China has three major deepwater oil and gas fields located in the Qiongdongnan and Pearl River Mouth basins in the South China Sea (SCS) at water depths ranging from 300 m to over 1500 m. In this paper we compare the geology, reservoir and fluid properties and development concepts of these deepwater fields with those in the Gulf of Mexico (GOM), Nigeria and Brazil. Based on this comparison, we have identified several key subsurface challenges and opportunities for future deepwater field developments in the SCS. Major subsurface challenges include smaller in-place volumes, heavier oil, lower reservoir energy and higher reservoir temperature. Opportunities identified include locating continental margin systems with high accommodation volumes and thick sandstone supply, use of alternative development concepts such as Floating Liquified Natural Gas (FLNG) and complaint platforms with dry tree wells and learnings from the recent development of lower-permeability reservoirs in deepwater GOM and the heavy oil deepwater developments and CO2 handling techniques in Brazil.

Summary Review of published geological data shows that permafrost regions in China's Mohe Basin, Qilian Mountain, and Qinghai-Tibet Plateau hold promise for gas-hydrate accumulation according to identifiable source rock, migration path, and reservoir seal, among others. In addition, they show some common characteristics: source rock consisting mostly of shale, relatively poor reservoir quality, and gas migration through fractures. However, formation lithology, source-rock type, origin of organic matter, and total organic carbon (TOC) exhibit significant differences.

Gas hydrate is a promising energy resource. Permafrost regions in China are natural gas hydrate prospects. In this study, we summarized the conditions for gas hydrate formation, and analyzed the probable thickness and area of gas hydrate stability zones in the permafrost regions in China. Then the probability of porosity within the gas hydrate stability zones was estimated from lithology, burial history, and compaction curves. Finally, the total reservoir volume for gas hydrate stability zones in permafrost regions was estimated from the joint probability distribution of the effective thickness, area, and porosity. The probable total reservoir volume of the gas hydrate stability zones in the permafrosts in China is in the range of 2.995 × 1012 m3 to 5.081 × 1012 m3, with the best estimate at 4.002 × 1012 m3. The Qinghai-Tibetan Plateau including Qilian (where the occurrence of natural gas hydrate has been proven by coring) has about 55% of the total reservoir volume of the gas hydrate stability zones in China, indicating it has a great resource potential. In the Mohe Basin the reservoir volume of the gas hydrate stability zone ranges from 0.49 × 1012 m3 to 0.79 × 1012 m3, suggesting it is a hopeful future resource exploration area. The best estimate of the total reservoir volume of the gas hydrate stability zones in Northwest China is 1.2 × 1012 m3 which is considerable. However, occurrence of gas hydrate is yet to be confirmed by future exploration. These estimates provide much needed data for further gas hydrate resource exploration and evaluation, as well as environmental protection.

In this study, a Na-montmorillonite clay-stabilized, oil-in-water (O/W) Pickering emulsion system was prepared and tested under high-salinity and high-temperature conditions. The emulsifying ability of the clay particles, emulsion stability against creaming and coalescence, and emulsion rheological behavior at different NaCl concentrations and temperatures were investigated. The results showed that decane could be effectively emulsified by clay particles into small emulsion droplets at salinities up to 25 wt% NaCl. The emulsion had a relatively narrow drop size distribution. However, the emulsion stability against creaming decreased with increases in NaCl concentration. At low NaCl concentrations, clay particles connected with each other by edge-edge and edge-face interactions, forming a three-dimensional network that stabilized the emulsion against creaming. A higher concentration of NaCl caused some clay particles to connect through face-face interactions, forming clay clusters. At high NaCl concentrations, the temperature had only a slight effect on the emulsion stability against creaming. However, emulsion stability against coalescence decreased with increasing temperature due to increased droplet collision caused by Brownian motion. A higher concentration of NaCl moderated this temperature effect of coalescence. The viscosity of emulsion decreased with increased NaCl concentration. Temperature increases caused emulsion viscosity to decrease at low NaCl concentration conditions. When the NaCl concentration was higher than 10 wt%, the temperature had little effect on the viscosity. In summary, this study identifies an O/W Pickering system with the potential for conformance control in high-salinity and high-temperature reservoirs.

Conventional drilling design inaccurately predicts the mud density required for borehole stability by assuming the porous rock is fully saturated with a single fluid while in reality it may be saturated with multiple fluids. However, the unsaturated poroelastic responses arising from the coupling of multiphase flow and mechanical deformation in a porous rock around a borehole have rarely been studied either numerically or analytically. For an inclined borehole in a formation saturated with two immiscible fluids, this paper presents a semi-analytical Laplace-type unsaturated poroelastic solution that takes into account the effect of interfacial energy by incorporating the equivalent pore pressure concept for an unsaturated (under-saturated) porous medium. The solution can be used not only to analyze the borehole stability during drilling but also to evaluate the poroelastic responses of a deeply excavated circular unlined tunnel in a formation saturated with water and gas. Based on the abovementioned fundamental Laplace-type solution, one further firstly proposes analytical unsaturated poroelastic solutions under four types of time-domain conditions including the instantaneous, modified instantaneous, short-time, and long-time ones. These different time-domain solutions can well guide the drilling engineer to design a more appropriate mud weight that minimizes the borehole collapse (breakout) from a conservative perspective. It is considered where the formation is saturated with water and oil, and the main results show that the phase-pressure differences that are determined by the two concepts of the equivalent and average pore pressure increase with increasing interfacial energy. The commonly used assumption that the formation is fully water-saturated overestimates the safe mud pressure window for borehole stability at early times but underestimates it at later times. Contrary to the classical elastic solution, the poroelastic solutions including the unsaturated and saturated ones show that the location of the borehole breakout does not always occur at the borehole wall. It first occurs at the borehole wall, then in the formation, and finally at the borehole wall as time progress. This is the result of variations in pore pressure and effective stresses with time. It suggests that engineers introduce the time-dependence and location-dependence into a mud-weight design to ensure borehole stability.

Summary Conventional drilling design assumes that the porous rock is fully saturated with a single fluid and therefore tends to inaccurately predict the mud weight needed for borehole stability because the pore space of the porous rock may actually have two or more fluids. This paper provides a new semianalytical poroelastic solution for the case of an inclined borehole subjected to nonhydrostatic stresses in a porous medium saturated with two immiscible fluids: water and gas. The new solution is obtained under plane-strain condition. The wellbore loading is decomposed into axisymmetric and deviatoric cases. The time-dependent field variables are obtained by performing the inversion of the Laplace transforms. On the basis of the expansion of the Laplace-transform solution, we derive the unsaturated poroelastic asymptotic solutions for early times and for a small radial distance from an inclined wellbore. Sensitivity analyses are performed on different ratios of bulk modulus of two fluid phases to pore pressures of the unsaturated case. In addition, the comparative analyses of pore-pressure differences are made between the unsaturated and saturated cases. The impact of the unsaturated poroelastic effect on pore pressure, stresses, and borehole stability is investigated. Our results show that the excess pore pressure caused by the poroelastic effect is generally higher for the saturated case (water) than the unsaturated case because of the large difference between the compressibility of fluid phases (water and gas). The time dependency of the poroelastic effect causes the safe-mud-pressure window of both the unsaturated and saturated cases to narrow and approach the long-time poroelastic one with increasing time. The safe-mud-pressure window narrows with increasing initial gas saturation. Contrary to the unsaturated case, the saturated case that assumes the formation to be saturated by one fluid (e.g., water) tends to optimistically predict a wider safe-mud-pressure window required for borehole stability. This new semianalytical poroelastic solution enables the drilling engineer to more accurately estimate the time-dependent stresses and the pore pressure around a borehole, thus allowing a mud weight design that will ensure borehole stability.

Naturally-occurring gas hydrate, either in deepwater continental margins or in permafrost regions, is a promising unconventional energy resource which has attracted a lot attention from governments and researchers. In this paper, we studied the phase behavior for methane hydrate and mixed-gas hydrate. Four permafrost hydrates and three marine hydrate deposits were selected for analysis. They were Messoyakha (Russia), Mount Elbert (Alaska), Mackezie (Canada), Qilian Mountain (China) in permafrost regions and Blake Ridge (West Coast of US), Shenhu (South China Sea), and Nankai Trough (Japan Sea) in deepwater continental margins. The thickness of the gas hydrate stability zone (GHSZ) was calculated and compared. Our results show that the thickness of the GHSZ in permafrost regions is 1.3 to 4.5 times thicker than that in marine regions due to three factors: lower mudline temperature, smaller geothermal gradients and higher percentage of non-methane gases. The ramifications are that both the gas initially-in-place and the gas production rate will likely be higher in the permafrost environment. In addition, like other unconventional reservoirs, sustained gas production from a gas hydrate reservoir will likely require constantly drilling new wells to replace declining production from existing wells. All these suggest that development of gas hydrate in deep marine environment may be cost prohibitive. On the other hand, the well cost and drilling challenges will be significantly lower in the onshore permafrost environment where the resource density is also higher. Consequently, we see more potential for commercial development of permafrost hydrates than marine hydrates.

At present, China has three major deepwater oil and gas fields located in the Qiongdongnan and Pearl River Mouth basins in the South China Sea (SCS) at water depths ranging from 300 m to over 1500 m. In this paper, we compare the geology, reservoir, and fluid properties and development concepts of these deepwater fields with those in the Gulf of Mexico (GOM), Nigeria, and Brazil. Based on this comparison, we have identified several key subsurface challenges and opportunities for future deepwater field developments in China. Major subsurface challenges include smaller in-place volumes, heavier oil, lower reservoir energy, and higher reservoir temperature. Opportunities identified include locating continental margin systems with high accommodation volumes and abundant sand supply, use of alternative development concepts such as Floating Liquified Natural Gas (FLNG) and complaint platforms with dry tree wells and learnings from the recent development of lower-permeability reservoirs in deepwater GOM and the deepwater heavy oil developments and CO2 handling techniques in Brazil.

Fractured shale gas wells often exhibit long-term linear flow. Previous studies have developed some linear flow models to analyse this behaviour. In this study, we developed a tri-linear flow model for simulating shale gas production. Our model does not assume that the length of secondary fractures is equal to the half-distance between adjacent hydraulic fractures, which is an improvement over previous tri-linear flow models. Based on the tri-linear flow model, we developed simplified equations for characterizing bilinear and linear flow regimes. Combining the tri-linear flow model and simplified equations, we developed a new rate-transient analysis (RTA) workflow to analyse shale gas production data. The new RTA workflow not only includes the identification of flow regimes and their analysis using a log-log plot of the reciprocal of production rate versus time, i.e., straight line analysis, but also history-matching. The results obtained from straight line analysis serve as additional constraints in history-matching. This helps to reduce the non-uniqueness issue of history-matching. The new RTA workflow was validated using two synthetic and five field examples.

In this paper, we present for the first time, a classification system for naturally-occurring gas hydrate deposits existing in the permafrost and marine environment. This classification is relatively simple but highlights the salient features of a gas hydrate deposit which are important for their exploration and production such as location, porosity system, gas origin and migration path. We then show how this classification can be used to describe eight well-studied gas hydrate deposits in permafrost and marine environment. Potential implications of this classification are also discussed.

This paper describes the interaction between hydraulic fractures and the multi-porosity system of matrix porosity and natural fracture porosity in shale reservoirs. During the process of hydraulic fracturing, a complex fracture network consisting of primary and secondary hydraulic fractures as well as natural fractures is created. It is postulated that only shale porosities connected with this network will contribute to hydrocarbon production. Furthermore, we propose a way to maximise well productivity by injecting micro-sized proppants that are less than 150 μm (100 mesh) into the natural fractures and secondary hydraulic fractures to prevent them from closing and thereby increasing the stimulated reservoir volume. The size of the micro-sized proppant should be designed to be between one-seventh and one-third the aperture size of the natural fractures. In addition, various materials for micro-sized proppants are proposed and discussed. Of these, hollow glass microsphere shows more promise because of its light density and track record of being used as an additive material in the oilfield. Although limited laboratory experiments and field tests have shown encouraging results of using micro-sized proppants to enhance the productivity of Barnett shale, more research is warranted to optimize the use of these micro-sized proppants in production enhancement in various shale formations.

Gas hydrate has been found both in the permafrost and deep ocean in China. However, due to easier access, much lower well cost and proximity to existing gas pipelines, gas hydrate in the permafrost is more attractive for commercial development. In this paper we examine the published data on gas hydrate exploration in various Chinese permafrosts, identify the key technical challenges and suggest directions for future study. Our study has identified Qilian Mountain Permafrost, Mohe Basin and Qinghai-Tibetan Plateau as the three permafrosts with highest potential for gas hydrate development. Of the three, only Qilian has confirmed occurrence of gas hydrate by coring. From the perspective of field operations, Qilian ranks highest in potential for development due to its proven hydrate occurrence, thickness of hydrate bearing layer and proximity to existing gas pipelines. Mohe ranks second due to its benign operating conditions. However, it lacks existing gas pipelines. Qinghai-Tibetan Plateau ranks third due to its high elevation which limits access and lack of oilfield infrastructure. We found that the key subsurface uncertainty is the gas hydrate saturation. There is little information on it for all three permafrosts. Other subsurface uncertainties include the thickness of the permafrost, geothermal gradient beneath the permafrost, porosity, gas hydrate composition and permeability of the hydrate-bearing layer. Future research needs to determine these reservoir properties accurately. Examination of core samples and logs from Qilian shows that gas hydrate distribution is discontinuous both vertically and areally. Therefore, a better way to quantify the uneven hydrate distribution in the reservoir is needed for reservoir engineering calculations. Current estimates of well production rate by reservoir simulation are sub-commerical and probably due to the assumption of pure methane hydrate which limits the thickness of the gas hydrate stability zone. Also, the assumption of using horizontal wells for hydrate production may be optimistic due to shallow depths and the discontinuous nature of hydrate distribution. Consequently, new recovery methods besides depressurization and thermal stimulation will be needed to increase the well production rate. Furthermore, we have identified a number of similarities in production engineering aspects of gas production from hydrate and coalbed methane (CBM) wells. Common challenges include reservoir depressurization by water production, solids production, need for artificial lift and difficulty in drilling long horizontal wells in shallow reservoirs. Therefore, some best practices from CBM production, such as pad drilling, artificial lift and water treatment methods, may be usable for gas hydrate production.

Commercial development of coalbed methane (CBM) in China has lasted for a decade. However, in 2015 annual CBM production in China was less than 5 Bcm and lagged far behind those in US (35 Bcm) and Australia (18 Bcm). In this paper, we review the published literature to determine the engineering challenges and opportunities of CBM production in China. Our review has identified seven major engineering challenges to CBM development in China. They are low cleat permeability and underpressured formation pressure of high-rank coals, ductility of coal seams, suboptimal fracturing fluids, formation damage during drilling, borehole instability in horizontal wells, frequent pump failures during production, and inadequate produced water treatment methods. Each of these challenges provides an opportunity for improvement. We propose a refocus on low-rank coals which have higher permeability. Other opportunities include development of better hydraulic fracturing fluids, non-formation damaging drilling fluids, use of geomechanics to understand borehole instability, optimization of the artificial lift methods and more robust and environmentally friendly produced water treatment methods.

During hydraulic fracturing, secondary fractures are created around hydraulic fractures and serve as important channels connecting the shale matrix and the hydraulic fractures. We developed an analytical model to simulate shale gas production from a multi-stage fractured horizontal well. The analytical model is based on the trilinear flow model, but it is free from the assumption that the length of secondary fractures is equal to the half-distance between hydraulic fractures. This analytical model captures the fundamental characteristics of a hydraulically fractured shale reservoir by incorporating transient gas flow in the matrix, secondary fractures, and hydraulic fractures. Because this model describes four linear flow systems (unstimulated reservoir volume, matrix in the stimulated reservoir volume, secondary fracture, and hydraulic fracture), it is called the quad-linear flow model. Production data from two shale gas wells were used to validate the model. Moreover, using the variance-based method and quasi-Monte Carlo simulation, we developed a stochastic framework to perform a probabilistic assessment of shale gas production. We also conducted a global sensitivity study with nine uncertainty parameters to identify important parameters and their interactions that affect well productivity. The results indicate that the existence of dense secondary fractures (the distance between secondary fractures is small) results in higher initial production rate and ultimate recovery, but a sharper decline in production rate. Increasing the length of the secondary fractures can more effectively enhance gas production in the presence of dense secondary fractures. Moreover, the benefits of dense secondary fractures are mostly limited to a high porosity shale reservoir.

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.

Summary Expandable sand screens were deployed successfully as a sand-control device in two horizontal openhole completions in two geologically different offshore fields in Brunei. A critical success factor was the choice of a drill-in fluid (DIF) that maintained hole stability and gave a near-gauge hole while running and expanding the sand screen. Field experience and extensive research led to the choice of a synthetic-based DIF for one well but a water-based one for the other. Challenges unique to the deployment of expandable sand screens in these wells are discussed.

Development of a coalbed methane (CBM) field in its early stage is often plagued by the lack of well control and scarcity of geological data over a large geographical area. Therefore, constructing a representative static model to estimate the in-place-volume presents a formidable challenge. In this paper we proposed a workflow to overcome this challenge and applied it to a CBM field in the northern Bowen Basin of Australia. This workflow may be considered as a best practice for the following reasons. First, it makes use of data from various sources including cores, well logs, seismic interpretation, and topography. Second, it performs rigorous quality control on these data, such as depth shift and log normalization. Third, coal ply division and correlation and subsequent structural modeling are based on three types of correlation: well-to-well, well-to-seismic and, well-seismic-Graphic Information System. Fourth, it establishes the low, base and high trends for the most important reservoir properties. Fifth, it constructs a base case static model by combining the aforementioned structural and reservoir property models. Sixth, it uses sensitivity analysis, which varies one reservoir parameter at one time, to rank the impact of reservoir parameters on in-place-volume. Seventh, it uses uncertainty analysis which varies all reservoir parameters simultaneously to arrive at the P10, P50 and P90 in-place-volumes and their corresponding static models which can then be used for reservoir simulations to estimate the recoverable volumes.

This paper presents a detailed case study of using surface to in-seam wells to develop a major coalbed methane (CBM) field in the Bowen Basin of Australia. This study was novel in that special emphasis was given to quantification of subsurface property uncertainty and modeling of dynamic uncertainty. The result was the generation of recovery factor versus depth correlations which can be used to calculate the estimated ultimate recoverable.In this work, a 3D box model around three pilot wells was extracted from the regional static model. To quantify key subsurface uncertainties such as permeability, both the Percentile and Confidence Interval Methods were used. Trends of laboratory-measured parameters like gas content, ash, Langmuir volume, permeability were established. Reservoir properties without measurements such as cleat porosity, desorption time and relative permeability were estimated based on rules-of-thumb, basin-wide analogue or educated guesses. A reservoir simulation model was built and production data from pilot wells were manually history matched. Parametric analysis was conducted to determine key parameters that significantly affect model history matching and forecasting results. Given the complexities of the coal reservoir and the non-uniqueness of the history match, Experimental Design was used to generate a population of simulation models that sampled the uncertainty range of key reservoir properties. This ensemble was reduced to include only those that matched the pilot wells’ production. With different combinations of reservoir properties thus obtained, recovery factor versus depth correlations were generated.This study is a good example of early resource assessment critical to the field development planning of a major CBM field. It presents a systematic method to handle uneven distribution of often sparse subsurface data over a large geographic area which often confounds the CBM industry. Furthermore, this method may be extended to assess other well architectures like vertical, slant, horizontal, multi-branch, multi-lateral and hydraulically fractured vertical and horizontal wells.

Summary Laboratory studies were conducted to determine the completion techniques for two wells in the Gulf of Mexico with well angles of 35 to 45°, completion intervals of about 400 ft, bottomhole temperatures of 222°F, and requiring a completion brine with density up to 17.0 lbm/gal. Three critical issues—fluid-loss control, pregravel-pack acid stimulation, and internal gravel packing—were studied. Laboratory studies showed that an activated hydroxyethyl-cellulose (HEC) pill could be designed to control the fluid loss for more than 30 hours, even at a bottomhole temperature of 222°R In addition, a high-rate acid stimulation could be employed to ensure that as many perforations as possible were open to accept gravel-pack sand. Physical model studies also showed that a high-rate squeeze waterpack provided the required effective perforation and annular packing for the target wells despite the long completion interval. These techniques were successfully implemented. Initial production data suggest that both wells, still under choke, are producing at expected rates, with low downhole drawdown.

Experimental studies have shown that the steam foam process can be significantly enhanced by injecting a suitably formulated alkali-surfactant mixture in the aqueous phase of steam. Emulsion screening tests, corefloods and flow visualization experiments using an alpha olefin sulfonate (AOS) surfactant with 16 to 18 carbon, Na2CO3 and a heavy Californian crude have shown that alkaline steam foam offers significant advantages over regular steam foam by combining the benefits of thermal and chemical enhanced oil recovery (EOR) processes. Firstly, Na2CO3 reduces surfactant consumption by adsorption by rendering the clay surface more negatively charged. Secondly, by precipitating divalent ions that get ion-exchanged off the clays, Na2CO3 reduces surfactant consumption by precipitation. Thirdly, a suitably formulated alkali-surfactant system reduces the oil-water interfacial tension (IFT) sufficiently to enable the heavy oil to be emulsified into the aqueous phase in the presence of steam. This oil-in-water emulsion is less viscous than that of the oil and can be readily transported. Consequently, the residual oil saturation is reduced to that below steam. Fourthly, this lower residual oil saturation reduces the destabilizing effect of oil on foam resulting in stronger steam foam that provides better mobility control than regular steam foam. Therefore, it has the potential to further reduce steam gravity override. Fifthly, the reduction in gravity override also reduces loss of heat to the cap rock. Steam utilization is thereby improved. When applied to steam drive, cyclic steam soaks and steam-assisted gravity drainage (SAGD) processes, alkaline steam foam has the benefits of increasing foam propagate rate, improving mobility control, improving steam utilization and reducing the residual oil saturation. In the cases of steam soaks and SAGD, it also increases the gravity drainage rate of oil by reducing the effective oil viscosity through emulsification.

Much of the development using horizontal well technology had been centered around drill-in fluids. These fluids tended to be excellent for completion purposes but poor drilling fluids, and although success was recorded throughout the world, many areas that required more robust fluids were not being drilled. Well conditions such as higher temperature (>175°F), depleted sands, intermittent sand shale layers, low fracture gradient pore pressure spread, and high weights for wellbore stability were limiting the application of horizontal well technology. Not only were fluids not available to drill with, but also it was unclear what methods or techniques were needed for wellbore clean-up. Because of need for drìll-in fluids, an effort was undertaken in concert with the service companies to develop fluids that met both drilling and completion requirements. The effort was systematic in that established criteria had to be met for both drilling and completion. These criteria included requirements on fluid rheology, thermal stability, lubricity, fluid-loss control, filtercake properties, and removal of filtercakes after drilling leading to low/no formation and screen damage. Laboratory tests to measure candidate drill-in fluids against these criteria were established. Both water and oil or synthetic invert fluids were developed. In this paper a quality procedure is shown for validating fluids on a screening basis followed by specific evaluation of methods to mix, maintain on the rig, and ultimately to complete. Our field experience has shown that this quality control procedure is crucial to the high success rate of Shell's horizontal wells in the Gulf of Mexico. Data are shown which lead to guidelines for drilling and completing wells with varying conditions.

Laboratory studies were conducted to determine the completion techniques for two wells in the Gulf of Mexico having well angle of 35 to 45 degrees, completion interval of about 400 ft, bottomhole temperature of 222°F and requiring a completion brine with density up to 17.0 lbm/gal. Three critical issues were studied. They were fluid loss control, pre-gravel-pack acid stimulation, and internal gravel packing. Laboratory studies showed that an activated hydroxyethylcellulose (HEC) pill could be designed to control the fluid loss for more than 30 hr even at a bottomhole temperature of 222°F. In addition, a high-rate acid stimulation could be employed to ensure that as many perforations as possible were open to accept gravel pack sand. Physical model studies also showed that a high-rate squeeze waterpack provided the required effective perforation and annular packing for the target wells despite the long completion interval. These techniques were successfully implemented. Initial production data suggest that both wells, still under choke, are producing at expected rates, with low downhole drawdown.

Abstract 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. Introduction Currently, China is the world's largest energy consumer and second largest oil consumer2. In 2011, 70.4% of China's energy consumption came from coal, 17.7% from oil and only 4.5% came from natural gas3. Emission from coal-burning power plants and automobiles are the two major sources of air pollution in China. Consequently, the key for China to move to a low-carbon economy is to reduce the use of coal and increase the use of natural gas. National consumption of natural gas in China in 2011 was 130.7 Bcm, a 21.5% increase from the previous year (Fig. 1). In the same year, national production of natural gas was only 102.5 Bcm. The gap of 28.2 Bcm, or 22% of national consumption, was satisfied by import by pipeline from Central Asia and from liquefied natural gas from Middle East, Africa, Australia and Southeast Asia3. In the last three years, the national consumption for natural gas has far exceeded domestic production. In order for this gap to be bridged, domestic production of natural gas, especially from unconventional resources such as coalbed methane (CBM), tight and shale gas reservoirs must be increased drastically. This need to grow domestic output of unconventional gas production has been recognized both by the government and private sector, thus giving tremendous impetus to the development of tight and especially shale gas reservoirs.

Summary The development of a coalbed-methane (CBM) field in its early stage is often plagued by the lack of well control and the scarcity of geological data across a large geographical area. Therefore, constructing a representative static model to estimate the in-place volume presents a formidable challenge. In this paper, we propose a work flow to overcome this challenge and apply it to a CBM field in the northern Bowen basin of Australia. One may consider this work flow as a best practice for the following reasons. First, it makes use of data from various sources including cores, well logs, seismic interpretation, and topography. Second, it performs rigorous quality control on these data, such as depth shift and log normalization. Third, coal-ply division and correlation and subsequent structural modeling are based on three types of correlation: well-to-well, well-to-seismic, and well-seismic-geographic information system. Fourth, it establishes the low, base, and high trends for the most-important reservoir properties. Fifth, it constructs a base-case static model by combining the aforementioned structural and reservoir-property models. Sixth, it uses sensitivity analysis, which varies one reservoir parameter at a time, to rank the impact of reservoir parameters on in-place volume. Seventh, it uses uncertainty analysis that varies all reservoir parameters simultaneously to arrive at the P10, P50, and P90 in-place volumes and their corresponding static models that one can use for reservoir simulations to estimate the recoverable volumes.

Summary In coalbed-methane (CBM) projects, conventional logs, such as density were used heavily for coal identification, coal-property derivation, and also potentially for coal ranking. This paper presents a novel work flow of density-log normalization for CBM wells. It addresses two major challenges to current normalization methods: absence of a pervasive reference layer and removal of geological effects after normalization. To overcome these disadvantages, the proposed work flow undertakes six steps, which are data quality control (QC), geological-area segmentation, subarea type-well selection, density-control points, variable linear transformation and normalized-log result QC with box plots, matrix crossplots, and several histograms. This work flow removes the systematic errors caused by acquiring logs at different times with different logging instruments provided by different vendors. Furthermore, it possesses the advantages of the automated QC work flow, type-well control, and reference-layer methods without incurring their respective disadvantages. It was applied successfully to approximately 600 wells covering a large area in the Surat basin of Australia. Proper log normalization will reduce the uncertainties involved in 3D geological modeling and will increase the accuracy of reservoir evaluation. This paper should therefore be of interest to petrophysicists and geologists involved in CBM-field characterization.

In coalbed methane (CBM) projects, conventional log such density has been used heavily for coal identification, coal property derivation and also potentially for coal ranking. This paper presents a novel workflow of density log normalization for CBM wells. It addresses two major challenges to current normalization methods, namely, absence of a pervasive reference layer, and removal of geological effects after normalization.To overcome these disadvantages, the proposed workflow undertakes six steps, which are data quality control, geological area segmentation, sub-area type well selection, density control points, variable linear transformation and quality control of log normalization results using box plots, matrix crossplots and histograms. This workflow removes the systematic errors caused by acquiring logs at different times with different logging instrument from different vendors. Furthermore, it possesses the advantages of automated quality control, Type Well Method and Reference Layer Method without incurring their respective disadvantages. It has been applied successfully to about 600 wells in the Surat Basin of Australia.Proper log normalization will reduce the uncertainties involved in geological modeling and increase the accuracy of reservoir evaluation. This paper should therefore be of interest to petrophysicists and geologists involved in CBM field characterization.

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° 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.

Summary Laboratory results demonstrate that surfactant adsorption on sandstones is minimized and foam performance improved by reducing the ethoxylate chain length in alcohol ethoxy sulfonates and blending unethoxylated and ethoxylated sulfonates to optimize desirable properties. The results also show that laboratory adsorption measurements can only be extrapolated to reservoirs by (1) replicating the anaerobic conditions of reservoirs, and (2) differentiating authogenic minerals from drilling mud found in reservoir cores.