A substantial increase in oil production resulting from CO2 flooding has been clearly identified in two multi-pattern areas of the SACROC Unit. Analysis of the two areas permitted the identification of oil response to CO2 injection with greater accuracy than has previously been possible at SACROC. The areas include the 600 acre [2.43 × 10 (6) m2] Four Pattern Area (4PA) and the 2700 acre [10.93 × 10 (6) m2) Seventeen Pattern Area (17PA). Located in the Kelly-Snyder Field of Scurry County, Texas, the 50,000 acre [202.3 × 10 (6) m2] SACROC Unit is the world's largest CO2 miscible flooding project. The 4PA encompasses 24 wells arranged in four contiguous inverted 9-spot injection patterns. The area has been on pattern waterflood since 1972 and was at a 95 percent producing water cut when CO2 water-alternating-gas (WAG) injection was commenced in June 1981. An approximate 30% hydrocarbon pore volume (HPV) of CO2 was injected over a 5-year period at WAG ratios ranging from two to eight. CO2 injection ceased in May 1986 and the area has been on continuous water injection since that time. Incremental oil recovery attributable to CO2 injection is estimated currently to be at least 9% of the original oil in place (OOIP). This represents an estimated cumulative CO2 utilization of 9.5 Mft3 per barrel of incremental oil [1692 m3/m3]. Also on pattern waterflood since the early seventies, the Seventeen Pattern Area has exhibited an approximate 5% OOIP recovery after injecting 17% cumulative HPV CO2. CO2-WAG flooding in the 17PA began in May 1981. Currently, the cumulative CO2 utilization is estimated to be 9.7 Mft3 per barrel of incremental oil [1728 m3/m3]. This paper examines the methods used to determine CO2 mobilized oil response, describes how the effects of workovers and other "normal" field operations were accounted for, and evaluates the influence of activities in patterns adjacent to the study areas. Introduction A substantial increase in oil production resulting from CO2 flooding has been clearly identified in two multi-pattern areas of the SACROC Unit. The intent of this paper is to document that response. CO2 performance reported herein is that which has been observed under "normal" field conditions and operations. SACROC DESCRIPTION AND EARLY PROJECT PERFORMANCE The SACROC Unit has been the subject of a great many papers dealing with the reservoir description, the CO2 displacement process, CO2 transmission, performance of the CO2 project, and many other topics. The history provided below, therefore, is only a synopsis. Early History of the Kelly-Snyder Field Discovered in 1948, the Kelly-Snyder Field is located in Scurry County, Texas (Fig. 1). The discovery well, Standard of Texas Brown 2-#1, was drilled to 6,700 feet [2042 m], 9 miles [14.5 km] northwest of Snyder, Texas. The well flowed 530 bbl/D [84.3 m3/d] from the Canyon Reef formation. Further development drilling proved up an area encompassing some 84,000 acres [340 × 10 (6) m2]. To date this discovery represents one of the last billion-plus barrel reservoirs to be found within the continental U.S.A. Pertinent reservoir data and properties are summarized in Table 1. P. 27^

Northwest to southeast regional scale flow in the Toro Sandstone parallels the Papuan Fold and Thrust Belt for a distance of 115km, passing through Iagifu/Hedinia oil field along the way. This has had a profound effect on oil distribution in the Toro there, having swept the northwest side free of moveable oil. A structurally controlled flow restriction causes a local, rapid drop in hydraulic potential, tilting local oil/water contacts up to six degrees and causing the three sandstone members of the Toro to locally behave as separate reservoirs, each with its own hydrocarbon/water contact. Reservoir simulations of Iagifu/Hedinia which include a flowing aquifer are able to match observed production history. Without a flowing aquifer, simulation predicts greater and earlier water production, and a greater pressure drop in the oil leg than has been observed. Reservoir modeling using a flowing aquifer has allowed downhole, structural targeting of later infill wells to be much closer to the OWC than would otherwise have been thought prudent, and has raised questions as to the potential effectiveness of a downdip water injection scheme. Production results from a small satellite field "upstream" of the main Iagifu/Hedinia field have shown a sudden increase in water production and reservoir pressure after a long period of pressure decline and no water production. This behavior appears to be due to an influx of higher hydraulic potential from a separate reservoir sand, the influx being brought about by pressure draw down during production and consequent breakdown of fault seal. Introduction Agogo and Iagifu/Hedinia fields in the Southern Highlands Province produced the first commercial oil in Papua New Guinea in June 1992. Oil is exported via a 261km pipeline that extends from the highlands to an offshore terminal in the Gulf of Papua (Figure 1). Much of Southern Highlands Province contains little or no infrastructure, and is characterized by rugged karst topography and dense rain forest. The karst and the Darai Limestone on which it is developed effectively preclude the acquisition of seismic data over most of the area with commercial discoveries. Lack of seismic data has forced a reliance upon field geology and remotely-sensed data, including side-scan radar, air photos, magneto-tellurics and gravity/magnetics, to decipher reservoir geometry. Adding to the challenge is aquifer flow resulting in a tilted oil-water contact (OWC) and a dramatic shift in the position of the oil leg in the Toro Sandstone reservoir in the main block of Iagifu/Hedinia field. The purpose of this paper is to show the evidence for a hydrodynamic reservoir, describe the interaction between structure, flow and the distribution of hydrocarbons, and detail how the flowing aquifer has been incorporated into reservoir simulation and development planning. P. 81^

A reservoir development plan was developed from a detailed geological model of the SE Gobe Iagifu reservoir. This model incorporated sequence stratigraphy and extensive core and log analysis to provide the detailed layering framework for reservoir simulation. Cross-sectional balancing techniques were applied to field derived dip and strike, dipmeter log, and RFT data to obtain a structural model for the reservoir. Cross-sectional, sector and, finally, full field reservoir simulation models were constructed and used by the team to generate a reservoir development and management plan. The simulation models were used to examine the relative merits of vertical, deviated and horizontal wells, well placement, offtake rates, gas compression requirements and pressure maintenance strategies. Due to the uncertainty in the size and shape of the field, development options were considered at each of three reserve levels: proven, probable and possible. The simulation results showed that well rates should be held to less than 8000 stb/d and that horizontal wells, with a length of at least 700 m, generally out-performed vertical wells. Oil recovery ranged between 34 and 45% of OOIP. The cases offering the best recoveries included both water injection and horizontal wells.

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