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Summary Surfactant/polymer (SP) flooding is an enhanced-oil-recovery (EOR) process that can lead to incremental oil recovery through two mechanisms: reducing oil/water interfacial tension (IFT) to decrease residual oil saturation and increasing the viscosity of the displacing fluid to improve overall sweep efficiency. IFT reduction allows better oil recovery by overcoming capillary effects, while the increased viscosity of the displacing fluid allows a more-homogeneous sweep of reservoir oil. Implementing chemical flooding in reservoirs with relatively high temperature and in-situ salinity (>200,000 ppm) is somewhat challenging. This paper describes the extensive laboratory work performed for the light-oil Raudhatain Lower Burgan (RALB) Reservoir (180°F/82°C) in Kuwait. Reservoir fluids were thoroughly characterized to preselect the most-suitable chemicals for the SP process. Reservoir crude oil was analyzed and recombined with gases (C1 through C3) depending on the reported gas/oil ratio (GOR) to reproduce the oil in place (OIP) at original reservoir conditions in terms of pressure, temperature, and oil composition. A shift of the live-oil equivalent alkane carbon number (EACN) was compared with the dead-oil EACN. Numerous surfactants were screened according to three main criteria: solubility in the envisioned injection brine, ultralow oil/water IFT, and chemical adsorption on reservoir rock. Different brine types were considered, and the use of adsorption inhibitors was also investigated. Furthermore, polymer screening involving temperature-resistant polymers was conducted by means of viscosity, long-term-aging, and adsorption tests. Polymer compatibility with the selected surfactants was also evaluated. The selected SP formulation was further evaluated through a series of coreflood experiments that were mainly dependent on chemical adsorption on reservoir rock and incremental oil recovery. An injection strategy was designed as a result of these experiments. Laboratory results obtained thus far are encouraging and provide a systematic methodology to design SP injection in high-temperature, high-salinity, and light-oil reservoirs that are similar to the RALB reservoir. Additional technoeconomic evaluation is in progress in preparation for field-scale deployment of SP injection at RALB Reservoir.

Sabiriyah Mauddud (SAMA) is not only a giant reservoir in North Kuwait with largest footprint it is also the most complex being carbonate. Presently, this reservoir is under waterflood which has helped to improve reservoir pressure and production performance. Production strategy of 1 million BOPD from NK reservoirs has brought focus on accelerated oil production by drilling new wells, good reservoir management practices and targeting difficult reserves. Possibility of early implementation of EOR has been considered as an option for SAMA. EOR screening studies were followed by extensive laboratory coreflood studies and sector model simulation study. In Lab, carefully designed recipe of chemicals (Alkali-Surfactant-Polymer) successfully addressed the critical issues of conformance control and adverse mobility ratio observed in SAMA to provide high displacement efficiency. Sector model was carried out to evaluate the different EOR processes like, gas, polymer and Surfactant-Polymer (SP). Encouraging oil recovery results were observed in lab and in sector model study with Chemical EOR which paved the way forward for testing it in reservoir. Success achieved through bench experiments and simulation study was transferred to the field last year when Single Well Chemical Tracer Tests with water and ASP recipe were conducted in three SAMA wells with successive improvement either in test procedure or in chemical formulation of the ASP. The result of the last test with ASP paid for all the hard work that was done with Sor brought down to 6%. Encouraged by these results, a small 6-acre inverted 5-spot pilot for Sabiriyah Mauddud is planned for 2016-17 success of which is a significant step for field wide implementation of EOR program.

This paper focuses on a chemical EOR feasibility study for Raudhatain Zubair (RAZU) reservoir in North Kuwait. The study describes a methodical approach to enable pilot location selection, and a fit-for-purpose modeling strategy to guide the Alkaline Surfactant Polymer (ASP) pilot design decisions. The objective of the pilot is to test in the field that ASP chemicals could mobilize remaining oil and drive it to the producers, where it is captured, produced and separated at the surface. A detailed study was conducted that focused first on mapping out the distribution of remaining oil in the Raudhatain Zubair (RAZU) sandstone reservoir, defining the subsurface uncertainties and identifying key decisions that needed to be addressed for the pilot design. Thereafter, a fit-for-purpose probabilistic dynamic model using a range of inputs based on available rock and fluid field data and ASP parameters from an in-house global Chemical EOR database was built. This model was used to predict the range of production outcomes and aid with pilot design decisions. Based on the stated objective of the pilot, an inverted 5-spot pilot pattern was chosen and a representative area was identified that spanned a reasonable average of field properties. An uncertainty analysis on the pilot pattern revealed that the residual oil saturation to both water and chemical and the remaining oil saturation at the commencement of pilot are the largest uncertainties governing the incremental oil recovery from ASP over water flood. Another significant uncertainty was the presence of an aquifer and the influence of active injectors near the pilot area. Depending on the aquifer strength and heterogeneity of the reservoir, fluid drift and can sweep the chemical slug away from the intended target region of the 5 spot pattern. On the design side, the chosen surfactant concentration in ASP slug, which affects the residual oil saturation to chemical, can result in lower than optimal oil recovery if surfactant losses (via adsorption or chemical consumption) are not adequately managed. Other important decisions are injection rate and pattern size since they affect the incremental recovery due to different swept pore volumes in the pilot pattern. Moreover, the model helped in steering important decisions for the pilot – e.g optimum time to switch to ASP injection after water flood. ASP sector models frequently suffer from being overly complex since they are not tailored to address practical questions that drive key pilot decisions in a timely manner. The unique practical modeling approach presented here focuses on identifying critical uncertainties and pilot design parameters while circumventing the need of detailed laboratory data and a full field model history match.

This paper describes the simulation of the Arun gas condensate reservoir using Mobil's fully compositional simulator, COSMOS (Compositional System Mobil Oil Simulator). The reservoir is a Miocene carbonate reef complex which occurs at a depth of approximately 10.000 feet, and is up to 1,000 feet thick in some areas. The Arun reservoir is a compositionally dynamic system. The purpose of this simulation study was to predict future reservoir performance under various demand scenarios and optimize gas and NGL recovery. The simulation mode utilizes the recovery. The simulation mode utilizes the Peng-Robinson equation of state to account for the compositionally dynamic behavior of the reservoir in predictions of future performance. The equation of state was modified by Mobil to incorporate special features for Arun such as water vaporization in the reservoir under high temperature conditions. A significant amount of time was spent on the geologic description of the field and initial data preparation, of the field and initial data preparation, which contributed to a good match of the historical data. The simulation model will serve as a reservoir management and planning tool to evaluate future operating strategies in the field. The technology presented in this paper is applicable to the management of other gas condensate reservoirs which exhibit physical phenomenal such as retrograde condensation, revaporization, and water vaporization. Introduction The Arun Field is located on the northern coast of Aceh Province in North Sumatra. The field was discovered in 1971 and is a giant gas condensate reservoir. Mobil Oil Indonesia operates the field as a Production Sharing Contractor for Pertamina. Gas is produced from the Arun Limestone at a depth of approximately 10,000 feet subsea. The gas pay is up to 1,000 thick in some areas. The initial reservoir pressure was 7,100 psig at the datum of 10,050 feet subsea, and is consequently overpressured. The temperature is 352 deg. F at this datum. At discovery, the reservoir was above the dew point, and had a stabilized condensate/gas ratio of about 48 STB/MMscf of water-free wellstream gas. The reservoir is underlain by an aquifer with a gas-water contact at about 10,600 feet subsea. Reservoir fluid properties and average rock properties and given in Table 1. The Arun Field began production in 1977. Field development was based on a cluster concept whereby only small areas of land are required for surface production and drilling facilities. This was done to minimize surface disruption to native farming and to the local community. There are four clusters in the field, each cluster designed to contain a maximum of sixteen wells. Producing wells are drilled directionally from these clusters. The gas is produced under a gas cycling scheme to maximize condensate recovery. Currently, there are ten gas injection wells located on the downdip perimeter of the field. The gas and condensate are delivered to the P.T. Arun LNG Plant for processing and liquefaction prior to export (Figure 1). The field production at present is about 2700 MMscf/D of separator gas, of which 800 MMscf/D are reinjected, 35 MMscf/D are used for fuel in the field, land 1865 MMscf/D are delivered to a 42-inch gas pipeline to supply two fertilizer plants and the P.T. Arun LNG Plant. About 135,000 bbl/d of unstabilized condensate are delivered to the P.T. Arun LNG Plant through a 20-inch pipeline. The Arun reservoir is a compositionally dynamic system. With pressure depletion, the water content of the reservoir gas increases significantly due to water vaporization under the high temperature conditions. Secondly, retrograde condensation and condensate revaporization effects impact compositional performance. Furthermore, injection of lean gas changes the fluid composition within the reservoir and reduces dew point pressure and hydrocarbon yields. Dissolution of hydrocarbons and carbon dioxide from both connate water and the aquifer also contribute to compositional changes. To properly fully compositional model was employed to simulate the field. P. 601^