Summary A test of cosurfactant-enhanced alkaline flooding, without polymer for mobility control, was conducted in a small reservoir in the White Castle field, Louisiana. Although the flood was unstable, the process recovered at least 38% of the waterflood residual oil in the reservoir as true tertiary oil and exhibited virtually 100% displacement efficiency. Alkali and cosurfactant propagated through the reservoir with acceptable and predictable losses. Introduction To demonstrate that cosurfactant-enhanced alkaline flooding1 is viable in recovering waterflood residual oil from sandstone reservoirs in the near-offshore Gulf of Mexico, a series of tests is being conducted in the White Castle field, Louisiana. The strategy adopted was to pilot the technology in three stages:a flood without polymer to prove features of the process unrelated to achieving mobility control,a test of process polymer injectivity in the same reservoir, anda full process demonstration in a shallower sand. The first phase of the pilot is described in this paper; pilot design, slug formulation, and operations are summarized and key responses are documented and interpreted. Ref. 2 describes the polymer injectivity test. The final pilot stage has not been initiated yet. Pilot Design and Operations Site Selection and Description. After screening of many potential sites, reservoirs in a small fault block in the Wilbert lease of the White Castle field were chosen for the cosurfactant-enhanced alkaline flooding pilot. Key properties of the White Castle reservoirs and their fluids (Table 1) are representative of Shell-owned targets for commercial processes except for the ˜45° dip in the salt dome White Castle reservoirs vs. 0 to 5° dip in the target fields. The difference in this parameter, however, was judged to be less significant because we thought its impact on process performance could be simulated adequately. Other attractive features of the White Castle field included its onshore location, stacked pays (enabling pilots in more than one reservoir with the same wells and surface facilities), proximity to chemical supplies, and infrastructure, all of which made operations less costly than in alternative locations. The reservoirs in the pilot fault block are bounded to the north and south by sealing faults and to the east (updip) by an impermeable shale sheath that drapes the salt dome (Fig. 1). The reservoirs communicate with strong aquifers through a nonsealing fault downdip. The Q sand was initially chosen for the first flood; shallower P and O 1 horizons, which were also deemed suitable, were left as either backups, if subsequent characterization work ruled out the Q sand, or objectives for follow-up pilot phases. Q-Sand Flood Objectives. The goals of the first phase of field testing of cosurfactant-enhanced alkaline flooding were (1) to validate designs of injection facilities; (2) to determine the injectivity of process slugs; (3) to establish the degree of gravity segregation during the process (vertical sweep efficiency); (4) to measure oil recovery, oil cuts, and process displacement efficiency; (5) to measure alkali consumption and surfactant retention; and (6) to gather information on treating produced fluids with conventional production facilities. Well Locations and Functions. To carry out the pilot, a pattern containing a downdip injector; two updip, gas-lifted producers; two logging observers; and a low-fate, rod-pumped sampling well was used (Fig. 1). All the wells used in the operations were drilled specifically for the pilot except the sampler; an existing penetration was recompleted to serve as that well. To obtain detailed petrophysical data on the pilot sands, pressure and rubber sleeve cores were taken when the injector and one of the producers (Well 267), respectively, were drilled. Residual oil saturation (ROS) determinations from core analyses, openhole logs, and a single-well tracer test 3 conducted through Well 267 were remarkably consistent, and the "average" value of 20% was adopted as the residual present in the Q sand. Before the alkaline pilot, Well 85 was the only well ever completed in the Q sand. Consequently, when Well 267 was added updip, it produced oil. To water out Well 267 (and thereby recover mobile oil lying even farther updip that might later compromise pilot interpretation), it was produced at ˜1,250 B/D, a rate more than five times that to be used during most of the pilot operations. During this prepilot attic drawdown, Well 267 produced 12,640 bbl of oil (the first 6,800 bbl at 100% oil cut) and 341,860 bbl of water. Wells 269 and 25, by contrast, both cut 100% water at the time they were completed in the Q sand. The logging observers, Wells 268 and 286, were cased with fiberglass so that process performance could be monitored with gamma spectroscopy, induction, and gamma ray logs. Facilities. Figs. 2 and 3 show the injection and production facilities used for the Q-sand flood. Because the methods of preparing injected fluids and handling produced fluids were unproved, these facilities were designed to provide flexibility for moving process fluids from one area of the facilities to another and with extensive capabilities for sampling and automated data collection. The injection facilities provided (1) storage for ample supplies of slug components, (2) blending and automatic monitoring (pressures, temperatures, pH, conductivities, oxygen content, flow rates, tank levels, and motor on/off condition) equipment, and (3) tanks to maintain a few days' supply of slug. An 02 scavenger (ammonium bisulfite) was added at various points to protect the facilities and well tubulars from corrosion. An on-site laboratory was equipped to perform the wet chemistry analyses needed to confirm that alkali, salt, and cosurfactant concentrations were within tolerances. Throughout the operations, injected fluid compositions were maintained within 5% of specifications, even when the facilities were operated by field personnel with no previous chemical-handling experience. A 30-day period during the drive when 0.4 rather than 1 wt% NaCl was mistakenly injected was the exception. p. 217–223

Naturally fractured carbonate reservoirs hold well over 100 billion barrels of heavy oil worldwide. Thermally Assisted Gas Oil Gravity Drainage (TAGOGD) is a new and novel thermal EOR technique, which has applicability in selected reservoirs. In conventional isothermal GOGD, vertical fractures cause the gas-oil contact in the fracture system to advance ahead of the gas-oil contact within the matrix blocks, causing the oil in these blocks to become mobile. The addition of heat in the fractures generates additional hydrocarbon gas cap, lowers the viscosity of the oil, and accelerates conventional GOGD, as seen in the 220 cp heavy-oil Qarn Alam field in Oman. Pilot results in the Qarn Alam field support the commerciality of this process, and a first-of-it's-kind steam injection project is being implemented. The economic success of the Qarn Alam project depends on the ability to credibly predict steam requirements and oil production. Two key oil production mechanisms are heat transport through the fractures and into the matrix, and subsequent gas cap generation due to thermal volatilization of the oil. The process mechanisms involved in TAGOGD were validated through laboratory experiments, while the field forecast model results were validated by history matching pilot performance data. A fully integrated workflow of fracture characterization, integrated reservoir physics, and static and dynamic modeling has enabled uncertainties and risks involved in developing the Qarn Alam field to be managed in a scenario based design approach. Introduction The Qarn Alam field is a highly fractured carbonate field that lies atop a salt diapir in Northern Oman. The 6 km long and 3 km wide field forms a relatively high-relief anticline with a N-NE by S-SW orientation. The reservoir is relatively compact dome-shaped structure, with a maximum oil column of 165 m. The main oil bearing reservoirs, the Shuaiba and Kharaib formations, are separated by a very low permeability oil bearing zone called the Hawar. The crest of the Shuaiba is located at 212 mss, and the original oil water contact is ∼375 mss. Fracturing occurs throughout all zones, and is believed to be contiguous and in hydraulic communication with a very active aquifer. The initial oil saturation is about 95% and initial water saturation is connate water. The matrix porosity is high (∼30%), while the matrix permeability ranges between 5 md-20 md. Under primary production, the reservoir produces on average about 100 m3/day of 16o API "heavy" oil, at a GOR of 10 m3/m3.

Ammonia is logistically preferred over sodium carbonate for alkaline/surfactant/polymer (ASP) enhanced-oil-recovery projects because of its low molar mass and the possibility for it to be delivered as a liquid. On an offshore platform, space and weight savings can be the determining factor in deciding whether an ASP project is feasible. Logistics may also be critical in determining the economic feasibility of projects in remote locations.Ammonia as alkali together with a surfactant blend of alkyl propoxy sulfate/internal olefin sulfonate (APS/IOS) functions as an effective alkali. Surfactant adsorption is low, and oil recovery in corefloods is high. Static adsorption tests show that low surfactant adsorption is attained at pH >9, a condition that ammonia satisfies at low solution concentration.It is expected that ammonia has a performance deficiency relative to sodium carbonate in that it does not precipitate calcium from solution. Calcium accumulation in the ammonia ASP solution will occur, caused by ion exchange from clays. The high oil recovery for ammonia and the calcium accumulation in ASP and surfactant/polymer corefloods with APS/IOS blends show that this surfactant system is effective and calcium-tolerant. Also, phase behavior and interfacial-tension (IFT) measurements suggest that APS/IOS blends remain effective in the presence of calcium. Ethylene oxide/propylene oxide sulfates (such as the used APS) are known commercially available, calcium-tolerant surfactants. However, because of hydrolysis, sulfate-type surfactants are suitable for use only in lower-temperature reservoirs.Very different behavior was noticed for phase-behavior measurements with calcium-intolerant surfactants such as alkyl benzene sulfonates and IOS. In this case, calcium addition results in a very high IFT and complete separation of oil and brine. Presumably, this will result in low oil recovery. A preferred approach for ASP offshore with divalent-ion-intolerant surfactants may be the use of a hybrid alkali system combining the attributes of sodium carbonate and ammonia. The concept is to supply the bulk of the alkalinity for an ASP flood by ammonia with all the inherent logistical advantages. A minor quantity of sodium carbonate is added to the formulation to specifically precipitate calcium ions.

Phase behavior experiments have identified several surfactant systems that develop high solubilization ratios and low interfacial tension with a specific dead paraffinic crude oil at specific salinities. The purpose of this work is to test these surfactant systems with reconstituted live crude. Emulsion screening tests were performed in sight cells where an equilibrium amount of solution gas is dissolved in the crude at reservoir pressure (1100 psi). The results indicate that the surfactant is relatively more soluble in the oil phase under these conditions. Thus a formulated chemical slug for field conditions should contain either less salinity or a more hydrophilic surfactant system than that used in formulations with dead crude. Phase behavior measurements estimate this offset to be approximately 0.25% less NaCl for the particular live crude in this study. The relevance of this offset is shown by comparing the results of dead crude core floods with a live crude core flood. A control experiment pressurizing oil with nitrogen at the same condition, 1100 psi did not show enhanced relative surfactant solubility in the oil phase.

Phase-behavior experiments have identified several surfactant systems that develop high solubilization ratios and low interfacial tension (IFT) with a specific dead paraffinic crude oil at specific salinities. The purpose of this work is to test these surfactant systems with reconstituted live crude. Emulsion-screening tests were performed in sight cells where an equilibrium amount of solution gas is dissolved in the crude at reservoir pressure (1,100 psi). The results indicate that the surfactant is relatively more soluble in the oil phase under these conditions. Thus, a formulated chemical slug for field conditions should contain either less salinity or a more hydrophilic surfactant system than that used in formulations with dead crude. Phase-behavior measurements estimate this offset to be approximately 0.25% less NaCl for the particular live crude in this study. The relevance of this offset is shown by comparing the results of dead-crude corefloods with a live-crude coreflood. A control experiment pressurizing oil with nitrogen at the same condition, 1,100 psi, did not show enhanced relative surfactant solubility in the oil phase.