Field Injectivity Experiences With Miscible Recovery Projects Using Alternate Rich-Gas And Water Injection

Unanticipated reductions in water-injection rates occurred in a miscible project using alternate injection cycles of rich gas and water to achieve an improved mobility ratio. The tentative explanation is that a small amount of oil remaining after passage of the rich gas causes a higher trapped gas saturation that lowers the relative permeability to water. Introduction Miscible flooding with hydrocarbon solvents has the potential for economically recovering a significant potential for economically recovering a significant incremental volume of oil over conventional waterflooding. However, poor sweep efficiency will occur unless the inherently unfavorable mobility ratio of solvent miscibly displacing oil is overcome. To control this problem and thus improve ultimate recovery, water may be injected before solvent injection and in alternate cycles with solvent. The injection performance of four field projects using the procedure of alternate water-solvent injection is presented. The solvent used is ethane and heavier components in the injected rich gas. In three of the projects, the injection of the water in alternate slugs projects, the injection of the water in alternate slugs with rich gas occurred at anticipated rates. In one West Texas project, however, an unanticipated reduction in the water-injection rates occurred after injection of the initial slug of rich gas. Unanticipated reductions in the water injection rates can seriously affect the present-worth economics of a project and add the risk of not maintaining the pressure levels required for miscibility at the rich-gas front. This paper presents the injection behavior experienced in the four field projects. Also presented are the results of diagnostic tests and remedial treatments that were performed in an attempt to define the cause of the performed in an attempt to define the cause of the unanticipated reduction in water-injection rates. A concept is discussed that could explain the cause of the reduced injection rates. In view of the uncertainties of assessing the cause of the problem in the atypical reservoir, the value of single-well injectivity tests before full-scale project expansion is pointed out. Most of the material project expansion is pointed out. Most of the material presented is related to the project that experienced the presented is related to the project that experienced the reduced water-injection rates. The other three projects are discussed briefly for comparison. Additional work was performed after preparation of this paper. The new work confirms and extends the concepts presented here concerning the cause of the reduced injectivity. Field Projects Project A Project A A miscible flood to recover secondary oil was designed for a West Texas reservoir, herein designated Project A, as described by Ballard and Smith. The dolomite reservoir produces 30 degrees API sour crude from a depth of 4,900 produces 30 degrees API sour crude from a depth of 4,900 ft. The average permeability of 2.1 md is the lowest of the reservoirs discussed in this paper. Other pertinent reservoir data are given in Table 1. The project is in a previously nonwaterflooded area that has been under partial previously nonwaterflooded area that has been under partial pressure maintenance by residue gas injection for 15 pressure maintenance by residue gas injection for 15 years before the start of the miscible project. The primary producing mechanism was by solution gas drive, producing mechanism was by solution gas drive, although an inactive aquifer and a gas cap existed at discovery. The project area is about 1,300 acres and the flood patterns are 42.5-acre five-spots with well spacing of 21.25 acres. There are 28 injection wells that affect 40 gross producing wells. JPT P. 1051