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CO2 has been successfully sequestered in aquifers at shallow water depth as supercritical CO2. However, at a water depth larger than 630 m in tropical regions, there exists a hydrate stability zone (HSZ) extending below the seafloor where CO2 and water can exist as solid CO2 hydrate. It is generally believed that CO2 cannot be stored inside the HSZ as formation of CO2 hydrate will impair CO2 injectivity. In this study, we investigate the feasibility of storing CO2 inside this HSZ by reservoir pressure management vis-a-vis the CO2 hydrate formation pressure through the use of water producers and CO2 injectors. We carry out simulations to investigate CO2 storage in three aquifers in tropical waters each with an area of 94 km2 (9.7 km × 9.7 km), thickness of 50 m, porosity of 30% and permeability of 3,000 md. Three confined aquifers are compared. Aquifer 1 is a shallow water aquifer without a HSZ. It has a water depth of 300 m and buried depth of 830 mbsf. Aquifer 2, straddling (60% inside and 40% outside) the HSZ, has a water depth of 800 m and buried depth of 70 mbsf. Aquifer 3, residing inside the HSZ, has a water depth of 800 m and buried depth of 30 mbsf. The reservoir pressure is managed by four corner wells which function either as CO2 injectors or water producers. We simulate CO2 injection into these aquifers with the help of water production to manage the reservoir pressure to stay below either the reservoir fracture pressure or the hydrate formation pressure. For Aquifer 1, our study shows that by reducing the reservoir pressure to below the fracture pressure through water production, up to 6% PV or 61 Mt of CO2 can be stored. The amount of CO2 stored is limited by the amount of water produced and the breakthrough of CO2 in the water producers. On the other hand, by reducing the reservoir pressure to below the hydrate formation pressure through water production, up to 12% PV or 164 Mt and 21% PV or 13 Mt of CO2 can be stored in Aquifers 2 and 3, respectively. Results show that during CO2 injection, CO2 hydrate formation delays CO2 breakthrough and moderates reservoir pressure due to volume shrinkage thus allowing more CO2 to be stored. Furthermore, over half of the CO2 is stored as immobilized CO2 hydrate which also limits post-injection migration of free CO2 and leakage through the caprock. These results demonstrate the potential of storing CO2 in aquifers having a HSZ with important ramifications for CO2 geological storage.

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.

Particle-stabilized Pickering emulsions are attracting increasing interest in oil and gas industries due to their unique rheological properties and stability. In this work, the rheological behavior of Na-montmorillonite stabilized oil-in-water (O/W) Pickering emulsions was studied under various salinities, pHs, clay concentrations and oil volume fractions. Results suggested that the Na-montmorillonite particles form a three dimensional network in water by different particle-particle interactions under specific salinity and pH values. The emulsion rheology can be explained by such clay interactions. The clay stabilized emulsion exhibits shear thinning behavior. At moderate salinities (around 0.25–5 wt% NaCl), the emulsion possesses a high viscosity of up to 100 mPa s at a shear rate of 7 s−1. Evidence suggests that a strong three dimensional clay network which connects the oil droplets is formed. The clay-droplet network possesses enough strength to withstand significant shear force, giving the emulsion a high bulk viscosity. Both too low and too high a salinity is unfavorable for maintaining a high emulsion viscosity. The gradual breakdown of the clay network with increasing shear rate accounts for the shear thinning behavior of the emulsion. The emulsion viscosity decreases with increasing pH as the clay-droplet network is more likely to form in an acidic environment. A two dimensional diagram summarizing the impact of salinity and pH on emulsion viscosity was generated. Emulsion viscosity also increases with clay concentration, but not always increases with oil volume fraction at a fixed clay concentration. The clay-stabilized emulsion shows significant elastic behavior. The clay network formed under a range of salinities and pHs is resilient to breakdown and has the ability to reform during strain, thus giving the emulsion a high elastic modulus. Our work shows that a clay-stabilized O/W emulsion system can possess high viscosity, shear thinning rheology and elasticity at high salinities and different pH of 3.3, 4.7, 6, 8, 9.5 and 11. These properties make the emulsion a potential candidate for various reservoir applications.

Coalbed methane (CBM) resources in China have been estimated to exceed 36 Tcm. As of 2014, there were ∼9300 producing CBM wells in China with an annual production of ∼4.4 Bcm. To satisfy its need for energy and to transition to a low-carbon economy, China has a big need to accelerate CBM development. This paper gives an overview of the status of CBM development in China, identifies key technical challenges, and proposes solutions to overcome them. Our review of the literature has revealed that current CBM development in China faces several technical challenges. Current projects are focused on high-rank coals in the Qinshui and Ordos basins, which have major geological and engineering challenges. The former includes low permeability, subhydrostatic reservoir pressure, and a lack of understanding of the connectivity of coal seams, which leads to difficulty in sweet spot indication. The latter includes difficulty in hydraulic fracturing in vertical wells, because of the ductile nature of the coal seams in th...

Water uptake induced by fluid&ndash, rock interaction plays a significant role in the recovery of flowback water during hydraulic fracturing. However, the existing accounts fail to fully acknowledge the significance of shale anisotropy on water uptake typically under in situ reservoir temperature. Thus we investigated the shale-hydration anisotropy using two sets of shale samples from the Longmaxi Formation in Sichuan Basin, China, which are designated to imbibe water parallel and perpendicular to shale bedding planes. All the samples were immersed in distilled water for one to five days at 80 &deg, C or 120 &deg, C. Furthermore, samples&rsquo, topographical and elemental variations before and after hydration were quantified using energy-dispersive spectroscopy&ndash, field-emission scanning electron microscopy. Our results show that shale anisotropy and imbibition time strongly affect the width of pre-existing micro-fracture in hydrated samples. For imbibition parallel to lamination, the width of pre-existing micro-fracture initially decreases and leads to crack-healing. Subsequently, the crack surfaces slightly collapse and the micro-fracture width is enlarged. In contrast, imbibition perpendicular to lamination does not generate new micro-fracture. Our results imply that during the flowback process of hydraulic fracturing fluid, the shale permeability parallel to bedding planes likely decreases first then increases, thereby promoting the water uptake.

Oftentimes an organizational transformation fails not because of external reasons but internal resistance. A step often neglected by senior management in organization transformation is aligning the transformation process with the corporate culture. When a transformation works against established corporate culture, it will be rejected by the organization and will eventually fail despite the best efforts by senior management. However, if an organization transformation is closely aligned with the corporate culture, its chance of success is greatly enhanced. In this paper, we propose a step-by-step procedure to align an organization transformation process with the four layers of corporate culture. This can be pictorially illustrated by the Corporate Cultural Onion Model and the Simple Lever Model of Organizational Alignment.

This paper discusses career development essentials for young E&P technical professionals to realize and use for career planning. By dividing the professional life of the E&P professional into the early-career, mid-career and late-career stages, each spanning about twelve years, the author discusses career development essentials and their benefits in each stage. In the early-career stage, essentials include understanding the corporate culture, developing technical depth and breadth and developing good interpersonal team skills. In the mid-career stage, essentials include developing leadership skills, moving out of one's comfort zone, mastering cross discipline competency and developing a strong professional network. In the late-career stage, essential include anticipating future trends, leveraging one's strength and experience, developing others and leaving a legacy.

Altering the wetting state of a rock surface to more water-wet has been proposed as an enhanced oil recovery (EOR) mechanism for nanoparticles. However, how nanoparticles achieve this is not well understood. The objective of this study is to fill this knowledge gap by using advanced 2D and 3D visualization techniques.In this study, advanced visualization techniques were used to study how hydrophilic silica nanoparticles change the wettability of a glass surface. First, we used interferograms of an oil drop resting on a nanoparticle-treated glass surface to analyze the effect of nanoparticles on wettability. Second, we used Atomic Force Microscopy (AFM) to characterize the structure of nanoparticles covering a glass surface. Third, we used a 2D microfluidic apparatus to visualize wettability alteration caused by the nanoparticle injection. Fourth, we used a fluoresence imaging method with confocal microscopy to find out the reason for this change.Interferograms of a nanoparticle-treated glass surface showed bright and dark fringes, indicating the presence of a thin water film covering the glass surface caused by nanoparticle adsorption. Furthermore, the higher the nanoparticle concentration, the thicker was the nanoparticle adsorption layer. A low pH environment can reduce nanoparticle adsorption on the glass surface. AFM results showed that the topography of the glass surface changed from smooth to rough after nanoparticle treatment. Microfluidic experiments showed that nanoparticle injection changed the wettability of the grain surface to more water wet. By using a confocal microscopy, we observed a thin water film covering the surface of glass grains suggesting that nanoparticle adsorption is the main mechanism of wettability alteration by nanoparticles.This paper presents findings of new techniques to study wettability alteration by nanoparticles, including thin-film interferometry, surface characterization by AFM, and fluoresence imaging with confocal microscopy. Observations showed that nanoparticles adsorption on a glass surface results in a thin water film that prevents the oil from contacting the surface. This is the main mechanism of wettability alteration by nanoparticles. This is the first time use of these advanced visualization techniques to study wettability alteration by nanoparticles is reported.

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.

CO2 solubility data in water at subsurface temperature and pressure conditions is important in global carbon cycle research. We measured the solubility of CO2 in H2O at a wide range of temperature from 313.15 to 473.15 K, and at the pressures from 0.5 to 200 MPa, and analyzed the effect of H2O vapor in the high-pressure-high-temperature (HPHT) system. The measured solubility is remarkably similar to published data at similar pressure/temperature ranges, while greater than the calculated values of existing prediction models at HPHT. This discrepancy is caused by the unneglectable increase of H2O vapor at HPHT, i.e., the decrease of liquid H2O in the system. The experiment data also suggests the dependence of CO2 solubility on temperature and pressure varies in different pressure-temperature regions. In the low-pressure region, the solubility depends predominantly on pressure and the value is small (generally smaller than 1 mol/kg). In the intermediate pressure region, solubility depends mostly on pressure, but the dependency is less than that in the low-pressure region. In the high-pressure region, temperature outweighs pressure in influencing the solubility. The sectional model provides more accurate estimations of CO2 solubility in H2O.

As 41 % of China’s CO2 emission comes from coastal provinces and cities, permanent sequestration of anthropogenic CO2 in offshore sediments is a priority to achieve China’s national goal of net zero by 2060. In this paper we evaluate the potential of CO2 sequestration in the major oil and gas reservoirs in the northern South China Sea (NSCS) bordering the southern provinces of Guangdong, Guangxi and Hainan. The calculation of the CO2 storage potential is based on voidage replacement for individual oil and gas fields. Our study shows that the overall CO2 storage potential in oil and gas reservoirs in the four major geological basins in NSCS has low, mid and high value of 1015.8, 1082.7 and 1151.5 Mt, respectively. About 84 % of the storage potential resides in gas reservoirs and 16 % in oil reservoirs. Though this storage volume is modest, it is adequate for an industry scale CO2 storage demonstration project where one to several Mtpa CO2 can be injected. Furthermore, we have identified two relatively mature gas fields, Dongfang 1-1 and Yacheng 13-1 in the Yinggehai basin as potential candidates for such a demonstration project where industrial CO2 from Hainan Island can be sequestered permanently. A feasibility study on this is warranted.

In this work, carbon nanotube (CNT) reinforced 316 L stainless steel (SS) composites were studied for the impact of CNT content on their microstructural, mechanical and tribological behaviour. Carbon nanotube-SS composites were fabricated via spark plasma sintering process at a sintering temperature of 800 °C. The tribological behaviour for pristine and 0.2, 0.5, 1.0, and 2.0 wt% CNT loaded samples was studied by a ball-on-disc tribometer under a normal load of 10 N at 28 °C and 300 °C. Microstructural studies showed grain refinement with the addition of CNT and hence enhancement in hardness and yield strength. The friction coefficients for high temperature tests were found to be lesser than that of room temperature values. Decrease in friction coefficient at high temperature tribotests compared to low temperature case could be attributed to the lubrication effect coming from local melting and CNTs. The lubrication of CNTs coming from its unique shape, aspect ratio, and flexibility. The wear rate was found to decrease with increasing CNT concentration in both cases. For the 2 wt% CNT case, the wear volume at 28 °C and 300 °C were nearly the same due to the lubrication effect. About 25% and 90% reduction in wear volume was observed for 2 wt% CNT sample at room temperature and 300 °C, respectively, when compared to their pristine counterpart. The composited samples showed increased resistance to wear than the pristine and commercial grade at both temperatures. A systematic study on the morphology, structure, hardness, yield strength, elemental composition, and tribology of the composites to understand the structure-property correlation of CNT-steel composite is presented in detail.

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.

This paper identifies several best practices for improving employee competency and productivity. They include aligning reward and promotion practices with company core values, promoting those who are already leading and have the capacity to perform at the next level, and using both internal and external benchmarking to help employees to set stretch goals for competency training and improving productivity.

In today's high-stakes E&P operating environment, achieving operational excellence is key not only to profitability but also obtaining a license to operate. Doing so requires E&P companies to have competent staff who are qualified to perform their jobs professionally at all levels of seniority. As technology and the regulatory environment change, continuous education for technical professionals is not only desirable but necessary. Competency-based training (CBT) is one of the most effective ways to ensure competency development in E&P professionals. Unlike traditional training, CBT focuses on helping the learner to master well-defined job-related competencies. The hallmarks of CBT are repeatability and reproducibility of results. Repeatability is the ability of the same learner to achieve consistent results whereas reproducibility is the ability of multiple learners to achieve the same consistent results. This paper discusses the ten elements of CBT in order to achieve repeatability and reproducibility.

Oil and gas industry is witnessing a rapid increase of interest in application of nanotechnology. Since last few years, nanotechnology is being studied as an alternative enhanced oil recovery (EOR) method and laboratory experiments have shown its potential. However, the adsorption behavior of nanoparticles in porous media and underlying mechanisms for improving oil recovery are still not well understood. The objective of this study was to investigate silica nanoparticles adsorption and displacement mechanisms at the pore scale within a micromodel. Another objective was to stabilize silica nanoparticles in the presence of crude oil at a high salinity and a high temperature for a longer period of time. A turbidity scanner was utilized to test stability of silica nanoparticles suspension in the presence of crude oil under 60°C. Turbidity stability index was used to evaluate stability of nanoparticles suspension and hydrochloric acid (HCl) was used as stabilizer to improved stability of nanoparticles suspension. The interfacial tensions (IFT) and contact angle between crude oil and the nanoparticles suspension with stabilizer were also measured. Both single-phase and two-phase flooding experiments were conducted for nanoparticles with and without stabilizer by using glass micromodels to visualize the nanoparticles adsorption and displacement behavior at the pore scale. Oil recovery was determined with image analysis to evaluate the potential of these nanoparticles for EOR applications. In addition, microscope images were taken and analyzed to investigate EOR mechanisms of nanoparticles suspension. Results of turbidity scanner showed nanoparticles behavior changed from aggregation to sedimentation. Silica nanoparticles suspension with HCl showed much better stability than the one without HCl under 3.8 wt. % synthetic sea water and 60°C condition. Wettability alteration between crude oil and water were observed with silica nanoparticles. For single-phase visualization flooding experiments, nanoparticles suspension with a stabilizer had less adsorption than the one without a stabilizer, and it could flow through micromodel without significant plugging. Nanoparticles adsorption can alter wettability of the micromodel to more water-wet. For two-phase visualization flooding experiments, injection of silica nanoparticles suspension with a stabilizer had better EOR result under high flow rate and can increase oil recovery about 3%. Wettability alteration and emulsification were proposed as main EOR mechanisms for nanoparticles. Silica nanoparticles stability behavior in the presence of crude oil under a high salinity and a high temperature was studied and the stability of nanoparticles suspension was quantified by using turbiscan stability index. Adding HCl as a stabilizer can reduce adsorption of nanoparticles in micromodel and avoid plugging. Enhanced oil recovery mechanisms of nanoparticles were investigated by using visualization micromodel flooding for better understanding of nanoparticles flooding.

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.

As petroleum projects becomes more international, there is more need for the petroleum professional to communicate across cultural boundaries. Intercultural competency on the part of the petroleum professional begins with an awareness of three types of cultures at work in the workplace: national, corporate and personal. Based on proven research in the field of cross-cultural communication, we propose using the Cultural Onion Model (Smith, 1992) to interpret these three cultures. This Model uses the analogy of an onion with four layers to represent the four layers of a culture. They are Behavior, Authority Structure, Experience and Core. Within a culture, the core contains the values and assumptions from which a culture develops. We then show how differences in core values concerning inequality, individualism, masculinity and uncertainty avoidance can affect the other layers of a national culture. Next, we explore how differences in corporate core practices can affect the culture of different types of company. Finally, we explore the implications of difference in both national and corporate cultures on three work-related areas: communication, leadership and reward system. Methods that work well in one culture may not work well in another, hence the need for cultural adaption. Our model will help the petroleum professional to understand important aspects of national and corporate cultures to become more effective in working across cultural landscapes.

Competency development in petroleum engineers is a life-long process. It starts with the undergraduate education and continues on throughout the career of the petroleum engineer. In this paper, we have identified the key competencies that need to be developed in the next generation of petroleum engineers in light of the increasingly complex, interdisciplinary and global nature of petroleum projects. These key competencies include dimensionsnot found in traditional petroleum engineering and geoscience (PE&G) programs such as leadership, health, safety and environment (HSE), interdisciplinary and intercultural competencies. Our research has shown that geophysics training is missing in most undergraduate PE&G programs. In addition, leadership training at the undergraduate level is a key need for future readiness of petroleum engineering students. The remaining core competencies, HSE, interdisciplinary and intercultural competency, are mostly learned at the workplace. Both university educators, corporate trainers and managers need to adapt their pedagogical methods to build competencies in Generation Y petroleum engineers. Suggestions of what they can do are given. To be effective trainers, they need to act more like mentors than teachers and supervisors.

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.

Based on a review of the leadership literature and personal observations, the author proposes a new leadership model for engineering managers (EM) in today's petroleum industry. This model consists of five essential leadership attributes. They are technical leadership, task leadership, relational leadership, change leadership and authentic leadership. Technical leadership refers to the ability of the EM to manage projects that are technically complex, multi-disciplinary and are subject to a high degree of technical uncertainty, such as field development planning. Task leadership refers to the EM's ability to be result- focused so as to complete the project on time, within budget and according to scope. Relational leadership refers to the EM's ability to motivate, challenge and support his or her team members to do their best. Change leadership refers to the EM's ability to promote innovative improvements to the organization and adaptation to external changes. Authentic leadership, which underpins all other leadership attributes, refers to the EM's ability to lead according to his or her core values which are ethical, commendable and consistent with those of his or her company, key stakeholders and the community. Suggestions on what universities, companiesand technical professionals can do to provide or acquire leadership training are also given.

Abstract A new method of coalbed methane (CBM) recovery is proposed wherein hot carbon dioxide at or near supercritical condition is injected into a CBM reservoir to take advantage of enhanced desorption of methane at elevated temperatures and the preferential adsorption of CO2 on coal surfaces compared to methane. The feasibility of this concept was studied by reservoir simulations using one quarter of an inverted five spot pattern using CO2 and CH4 adsorption isotherms published in the literature. The study compared CBM recovery by pressure depletion, CO2 injection and injection of CO2 that is 10°C hotter than the reservoir temperature. Results show that hot CO2 injection can significantly increase the production rate and recovery factor over and above that achievable by reservoir heating or CO2 injection alone. This new method holds promise for enhanced CBM recovery and also CO2 sequestration, especially for high-rank coals where swelling of coal by CO2 injection is minimized. Preliminary considerations suggest that this method can be economic over a range of CO2 and natural gas price if the CO2 comes from natural sources and the CBM field is located near an existing CO2 pipeline. Alternatively, if the source of CO2 is industrial, this method can be profitable if the cost of CO2 capture is offset by the trading price of CO2 and if the CBM project is located near the CO2 source. Introduction Coalbed methane, also known as coal seam gas, is a significant source of natural gas worldwide, with sizable reserves in the United States, Australia, Russia, Canada and China. In 2015, CBM production in the US was 1.27 Tcf (35.97 Bcm), accounting for 3.9% of all US natural gas production (EIA, 2017). Commercial production of CBM occurs in ten US basins with major production coming from the San Juan, Black Warrior and the Central Appalachian. In 2015, CBM production in Australia was 270 Bcf (7.65 Bcm) accounting for 18% of Australia's total natural gas production (Australian Government, 2016).

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.

Nanotechnology is the design and application of engineered or naturally occurring nanoparticles with at least one dimension of the order of 1–100 nm to accomplish specific purposes. Nanoparticles possess three unique properties. First, their small size enables nanoparticles to be transported into formation pores not accessible to larger particles. Second, at nanoscale, material properties are size dependent. Therefore nanoparticles can be engineered to contain specific optical, magnetic, interfacial, electrical or chemical properties to perform specific functions. Third, they have a very large surface-to-area ratio. Combined together, these unique properties allow nanoparticles to be used for many purposes in the oilfield. The objective of this paper is to conduct a critical review of the recent literature to determine the status of research and development and field application of nanotechnology to the oilfield. Most of the proposed applications of nanotechnology in the oilfield can be classified into the following six areas: (1) sensing or imaging, (2) enhanced oil recovery (EOR), (3) gas mobility control, (4) drilling and completion, (5) produced fluid treatment, and (6) tight reservoir application. Our review shows that much of the current research is focused on the performance of nanoparticles in the reservoir. Some work is done of the propagation of nanoparticles and very little work is done on the delivery and recovery of nanoparticles. In addition, a lack of well-defined health, safety and environmental protocols for safe delivery and recovery of nanoparticles can be a showstopper and more focused research is needed in this area. Our work also shows that affordability of nanoparticles is another showstopper due to the large quantity needed for oilfield applications and the current lack of vendors. As a remedy, we propose focused research and development on the use of naturally-occurring and industrial waste nanoparticles for oilfield applications. Of the six application areas, we rank imaging, drilling through unstable zones, tight reservoir applications and EOR as ones having the biggest potential impact. Using nanoparticles to detect hydrocarbon saturation in a reservoir can significantly impact how we plan field development, such as well placement. Similarly, using nano-enhanced drilling fluid to stabilize and drill through unstable zones can increase rate of penetration, reduce drilling cost and minimize environmental impact. Furthermore, using specially-designed nanoparticles to image and prop up induced and naturally occurring fractures in tight reservoirs can lead to sweet spot identification and more prolific wells. With its ability to make reservoir rocks more water-wet, waterflooding by nanofluids also has the potential to augment or replace low-salinity waterflooding as an EOR method.

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.

Summary 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, Tm; and adjustable Tm over a wide range of temperatures. Because succino-glycan 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, we 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 succino-glycan 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.

This paper presents the results of laboratory experiments and field trials on a polysaccharide biopolymer, succinoglycan, for use in gravel packing. This biopolymer causes minimal formation damage and has unique rheological properties that combine high shear-thinning behavior with temperature-induced viscosity breakback; thus, it can be used without breakers. A scouting study has been carried out at KSEPL to identify new viscosifiers with better rheological properties that cause minimal formation damage. Ideally, breakers should not be required and on-site polymer preparation procedures should be simple enough to give reliable, repeatable performances. For slurry-pack-type operations, the polysaccharide biopolymer succinoglycan was identified as the best candidate. The biopolymer was developed for EOR during 1980--83 at the Sittingbourne Research Centre, Shell Research Ltd., U.K., and is marketed by Shell Intl. Chemical Co. Ltd. as Shellflo-S.''

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.

Abstract Although smart wells have gained acceptance in the industry1–3, the integrated workflow needed to progress a portfolio of smart well opportunities requires systematic attention. In some cases, smart wells fail to materialize not because technologies are not ready but because of lack of participation and integration of relevant disciplines in a timely fashion. This paper summarizes the good practices used by one operator to progress a portfolio of smart well opportunities in a number of major projects. The smart well workflow is divided into six phases: Identify, Assess, Select, Define, Execute and Operate. The objectives, technical considerations, contribution from various disciplines, key success factors and good practices of these phases are defined and detailed. A key to successfully progressing smart well opportunities in a project is to identify and work the interfaces between the relevant disciplines. In the first three phases, the project team identifies the opportunities and assesses the feasibility of various smart well options. The optimum smart well solution is then selected through quantification of both the risks and benefits of these options using a multi-disciplinary approach. Quite often smart wells are advocated by one discipline without sufficient buy-in from other disciplines. This often leads to a weak business case and failure to adopt smart wells by the project team. In the Define Phase, attention should be placed on ensuring that smart wells components are compatible with other components in the well, subsea and surface systems. In the Execute Phase, a rigorous QA/QC program is key to successful installation. In the Operate Phase, a Collaborative Work Environment is recommended to bring data, information and people from different locations together to facilitate timely decision making to optimize the value of the asset. Introduction In this paper, a smart well is defined as one that consists of both downhole sensing and flow control. Typical downhole sensing devices include permanent pressure and temperature gauges, flowmeter, and distributed temperature sensing (DTS). Other devices include cableless communication and downhole geophones for detecting microseism. Typical downhole controls include interval control valves (ICV) and auto gas-lift valves. Interval control valves can be on/off, multi-positioned, or infinitely variable. They may be actuated by hydraulic or electrical control lines or both. The degree of smartness should be fit-for-purpose and defined in the early stages of a project. A smart field4–6 usually consists of one or more of the following: smart wells, smart facilities, and an aerial reservoir surveillance program, e.g. 4D seismic. A field becomes smart when information from these technologies can be assessed, evaluated and analyzed by relevant disciplines to make timely decisions to optimize the productivity and recovery of the field. While this paper focuses on smart wells, how smart wells fit into the overall smart field implementation will be discussed.

Abstract Expandable sand screen (ESS) is a sand control technique that has the potential to give a lower skin and therefore better productivity than other conventional sand control techniques, such as internal gravel packs (IGP's), openhole gravel packs (OHGP's), and stand-alone screens. However, welldocumented field cases in public literature that confirm this potential have not been reported to date. Over the last few years, Brunei Shell Petroleum (BSP) has applied the ESS technology in both cased hole and openhole completions. The productivity data of the ESS-completed zones have been used in a comparison with data from similar zones completed with more conventional gravel packs. In openhole applications in BSP's S.W. Ampa and Champion fields, production results show that the Productivity Index (PI) of ESS-completed reservoirs is equal to or better than expected, with one ESS zone having some 50% higher PI than similar OHGP zones. In cased hole applications in the Champion West field, the productivity of reservoirs completed with ESS is similar to or better than the productivity of similar reservoirs completed with IGP's. In all cased and openhole ESS-completions, no indications of sand production, screen plugging or screen erosion have been observed to date. Introduction Expandable sand screen is an emerging sand control technology that can be applied in cased and openhole completions, as an alternative to internal gravel packs, openhole gravel packs or stand-alone sand screens. It offers several advantages over conventional gravel packs: easier logistics, simpler operations (with potential for rigtime savings especially in cased hole completions), larger bore access to the completed zone, better support of the formation in openhole completions, and potential for remedial zonal isolation. It also has the potential to give a lower skin and therefore better productivity than other conventional sand control techniques. The concept and the development of the ESS technology has been described in more detail in Refs 1, 2. Since the end of 1999, BSP has been applying the ESS technology in both cased hole (5 wells) and openhole (4 wells) completions3, 4. In several campaigns similar wells and zones have been completed with ESS or conventional sand control methods, providing excellent comparison material between the two. The production data from these zones have been analysed and used in a discussion on the merits of ESS from the perspective of well productivity. Openhole ESS Applications in S.W. Ampa Field The S.W. Ampa field in the Offshore West concession area of BSP consists of many thinly stacked sand layers separated by shale stringers. Many reservoirs have a history of sand production thus making sand control a necessity. Sand control in openhole completions transecting multiple sand layers is particularly challenging due to shale instability issues. This field had a history of unsuccessful openhole gravel packs thought to be associated with the collapse of shale once the openhole was displaced to brine. Caliper logs showed that with increasing openhole time, the shale section became overgauge while tight spots developed in the sand sections.

In February 2000 BSP drilled and completed its first internal gas injector in the SW Ampa Block 11 field. Well SWA-285 causes deliberate crossflow of gas from the deep AW/AX gas reservoirs into the gas caps of the overlying AV oil reservoirs (Fig 1). The result is a pressure maintenance scheme that does not require any surface facilities. New production technologies employed (including long openhole gravel pack, surface-controlled interval control and lubricator valves and permanent downhole gauges) allow both control and monitoring of the downhole gas injection scheme. After 17 months of injection, the increase in AV reservoir pressure recorded in a number of observation wells and the favorable production from downdip wells in both easten and western flanks have confirmed that the internal gas injection is yielding the desired results. As a consequence of these encouraging results, a downdip horizontal well was recently drilled to capture the benefits of the first internal gas injector. In addition, a second internal gas injection was recently drilled in an adjacent block (Fig 2).

In the last three years, openhole horizontal gravel packs have been used extensively in Brunei Shell Petroleum as a sand control method in horizontal wells. Several reasons contributed to the wide application of this completion method. First, production data indicated that horizontal openhole reservoir sections completed with stand-alone screens showed productivity decline possibly caused by screen plugging. Second, gravel packing increases the inflow area and moves damage away from the screen, thus delaying or minimising screen plugging. Third, being an openhole completion a horizontal openhole gravel pack gives a lower skin than a cased-hole completion. To date, Brunei Shell Petroleum has successfully installed twenty-one horizontal openhole gravel packs with lengths ranging from 100 m to over 1000 m. The unique challenges for horizontal gravel packing in Brunei reservoirs include shallow true vertical depth, long horizontal lengths up to over 1000 m, hole sizes ranging from 6" to 9-7/8", and well paths that crossed faults and long shale sections. Current production from the wells completed with openhole gravel packs accounts for some 18% of Brunei Shell's total oil production.

Expandable Sand Screen (ESS®) was 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 during running and expansion of the ESS. Field experience and extensive research led to the choice of a synthetic-based DIF for one well but a water-based DIF for the other well. Challenges unique to the deployment of ESS in these wells are discussed.

This paper discusses a novel development concept of internal gas injection, in which the energy of gas reservoirs is used to maximise production and ultimate recovery of depleted oil reservoirs. The South West (SW) Ampa Block 11 field in Brunei is characterised by highly stratified formations containing numerous, often areally extensive, stacked thin reservoirs alternated with sealing shales. The sequence contains a variation of oil, gas, oil rim and water reservoirs. Due to faulting and reservoir shale-out, Block 11 oil reservoirs are isolated and therefore lack support from an active aquifer. The pressures in the oil reservoirs have declined severely, resulting in low production rates and a low ultimate recovery (current recovery factors range from 20% to 40% for individual reservoirs). A novel development concept of internal gas injection is now proposed to provide energy to the oil reservoirs at low unit cost. Block 11 contains gas reservoirs that underlie the more shallow oil reservoirs, and contain an abundance of energy. The internal gas injection scheme will be implemented by drilling two "injection" wells. Within each well-bore gas will be produced from the gas reservoirs and injected directly into the oil reservoirs. The process will be controlled using intelligent well completions. The scheme will substantially increase the oil production rates and reserves. The injected gas will be back-produced both during the proposed development and after economic oil production has ceased, without loss of gas ultimate recovery. The proposed internal gas injection scheme is believed to be an industry first.

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 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. These properties include increased mobility reduction, more gas-oil foam formation, and enhanced surfactant transport in the oil and water, which all appear to be negatively affected by the presence of long ethoxylate chains in a surfactant. A series of experiments are used to show that laboratory adsorption measurements can only be extrapolated to reservoirs by 1) replicating the anaerobic conditions of reservoirs, 2) matching the reservoir pH in a CO2 flood and 3) differentiating authogenic minerals from drilling mud found in reservoir cores. Introduction If a foam is to be designed to provide mobility control throughout large reservoirs with several thousand feet between wells, the properties of that foam and the surfactants used to create the foam must differ substantially from foams and surfactants used to reduce mobility in near well bore applications. Previous papers describe some of these differences. First, oil is likely to spread1 around carbon dioxide rich gas bubbles when they are some distance from a injector because light hydrocarbons have not yet been stripped from the oil. Next, it is absolutely necessary to maintain very low surfactant adsorption and little mobility control in order to afford such a foam, yet the foam must survive in the reservoir in the presence of a high capillary pressure. Surfactants with very high critical Micelle Concentrations (CMC) used below their CMC appear to satisfy these criteria2. Surfactants used below their CMC have low adsorption and limited mobility control because solid-fluid and fluid-fluid interfaces are not completely occupied by surfactant molecules. Thus, surfactant adsorption is so low that low concentrations of surfactant can propagate faster than high concentrations2–4. Yet foam stability and mobility control are sufficient to limit gravity override of gas2. Finally, surfactant must somehow propagate where water is not mobile. A good example of this is at the top of an oil reservoir where water saturation is low, water mobility is low, and surfactant does not propagate far in the water. A possible solution to this dilemma has been suggested. It has been shown 5 that the portion of a surfactant which dissolves in the oil does propagate where water is immobile and can stabilize gas-oil lamellae. This gas-oil foam was observed in microvisual experiments at reservoir conditions, shown to reduce mobility when water was absent, and shown with simulations to be the likely cause of mobility control in laboratory experiments.