Injectivity and Gravity Segregation in WAG and SWAG Enhanced Oil RecoveryA. Faisal AbstractGas-injection enhanced oil recovery can recover nearly all residual oil where the gas sweeps. Sweep efficiency in these processes is often poor, in large part because of gravity override of gas. Stone and Jenkins presented a model for gravity override in homogeneous reservoirs, showing that the distance gas and water travel before segregation depends directly on injection rate. In cases where injection pressure is limiting, injectivity is key to overcoming gravity override.Stone assumed continuous injection of gas and water as a model for WAG (Water Alternating Gas), contending that this is valid as long as slugs mix near the well. This model for co-injection can be extended to relate segregation distance for co-injection processes directly to injection pressure. Injectivity depends on saturations very near the well, however. Therefore, where injection pressure is limiting, this model is pessimistic because injectivity in WAG is greater than in co-injection.We investigate the increase in injectivity possible with WAG compared to co-injection in 1D and 2D, and the implications for gravity override in 2D, using a range of models for gas and water relative permeabilities. We confirm that the greater injectivity of WAG improves vertical sweep compared to Stone's model when injection pressure is limiting. The greatest improvements occur when slugs violate Stone's assumption: that is, when they are too large to mix fully near the well. The increase in injectivity over co-injection is greater for foam than for WAG without foam, because foam has much lower mobility when gas and water flow together.

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The paper describes the reservoir management experiences of Kerisi field after seven years of production. Kerisi field is located in Block B of South Natuna Sea and comprises five separate reservoirs in three geological zones.Forty seven percent of the reservoir hydrocarbons are located in the Upper Gabus Massive West (UGMW) reservoir; optimum production from this formation is expected to be reached by injecting gas at the gas cap. The source of injected gas is from all five Kerisi reservoirs and the nearby Hiu field. The liquid hydrocarbon production from UGMW and the production/injection of Kerisi -Hiu produced gas in this formation is of high importance to the future development stage of Kerisi -Hiu field.The initial reservoir management strategy was to optimize oil value with injection while meeting gas sales requirements. Both gas sales commitments and injection targets were honored with high Kerisi -Hiu production and the strong performance from other gas fields.With time, other gas fields became depleted faster than expected. Thus, it was decided to reduce gas injection rate in UGMW and produce more Kerisi and Hiu gas to increase gas sales volumes. The reduced of injection rates improved short term economic of the fields, but the effect to reservoir and long term economic benefit still needs evaluation. This paper will (1) show the impact of varying injection rate at UGMW to the overall Kerisi -Hiu field future production, include oil, gas, condensate, and LPG, (2) discuss an updated -improved reservoir management strategy, and (3) present an economic evaluation of the updated reservoir management strategy for the Kerisi -Hiu fields.The purpose of the paper is to share lessons learned in the evaluation of historical performance, data acquisition and monitoring, static and dynamic modeling, history matching, prediction of future performance, and the dynamics of reservoir management strategy which support future profitable opportunities.

X gas field is located in the Corridor block of Onshore South Sumatra, Indonesia and operated by ConocoPhillips Grissik Ltd. (CPGL). The field was first discovered in 1994 and started production in 2001. In terms of reserves, X field is the second largest in the Corridor. All production comes from fractured igneous (granite, granodiorite) and metamorphic (meta conglomerate, quartzite, phyllite and marble) rocks of the pre-Tertiary basement. To date, eight wells have been drilled during the exploration and development program. The most recent development well was the X-8, which was drilled in 2017. The X-8 well was designed to enter the top of the reservoir structure at a location where the seismic amplitude exhibited dimming. Based on analysis of the seismic and well productivity, dimming amplitudes are indicative of faults and fractures. Historically, exploration, appraisal and development wells drilled in the field did not experience any wellbore stability issues. During drilling of the X-8, wellbore stability and collapse caused significant problems and resulted in the sidetracking of the well three times. Prior to the drilling, it was recognized that depleted reservoir conditions may result in wellbore stability issues, but the rock strength was determined to be sufficient to overcome any wellbore collapse. It would only be necessary to overcome the pressure difference, and this could be done using managed pressure drilling (MPD). Although MPD was implemented successfully, the wellbore collapsed during drilling and before the completion string could be run. Ultimately, the well was completed using the drill string since standard completions were impossible under the time constaints. An after-action review of X-8 was conducted, and hypotheses were generated to explain the wellbore stability issue in this well. The review included fault interpretation uncertainty, lithology competency, reservoir lithology and geomechanics. Based on this work, two explanations were suggested as the main cause of wellbore collapse. The first explanation is that the top of the basement consists of a weathered zone resulting from exhumation in the Mesozoic. The weathered zone consists of rock material generated by both physical and chemical weathering. The second explanation is shear failure due to reservoir depletion. Both explanations are supported by well data, seismic attributes and current reservoir pressure. In the end, with an understanding of the potential failure mechanism, the last sidetrack was completed by leaving the drill string inside the hole to enable the well to produce. The learnings suggest that drilling through fracture basement reservoir is challenging and with depletion, the reservoirs can be nearly impossible to drill. Casing or liner drilling may be the only solution to successfully drill these types of wells and produce the hydrocarbons.

A Gabion stepped weir is a permeable weir that consists of a gabion box filled with stone aggregates. It is cost effective structure used for the dissipation of water flow energy from upstream to downstream. Gabion weir also allows the movement of aquatic life and transportation of physical and chemical substances present in water. In this study, energy dissipation in terms of inverse relative energy dissipation (IRED) over gabion stepped weir has been studied. It is observed that the existing predictor does not give a reasonable estimate for IRED. Therefore, the data have been reanalysed to develop a generalized regression equation for IRED. Generalized models using Gene Expression Programming (GEP) and Group Method of Data Handling (GMDH) were also developed. The predictions based on GMDH model(R=0.979,E=0.96 and RMSE=0.314) were found more satisfactory than those given by traditional regression equations(R=0.929,E=0.91 and RMSE=0.557) as well as the GEP model(R=0.959,E=0.94 and RMSE=0.476).