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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.

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).

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.

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.

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.