Abstract. A pilot scale field test of non-aqueous phase liquid (NAPL) removal using high molecular weight alcohols was conducted at Operable Unit 1, Hill Air Force Base, Utah. Petroleum hydrocarbons and spent solvents were disposed of in chemical disposal pits at this site, and these materials are now present in the subsurface in the form of a light nonaqueous phase liquid (LNAPL). This LNAPL is a complex mixture of aromatic and aliphatic hydrocarbons, chlorinated solvents, and other compounds. The field experiment was performed in a 5 rn by 3 rn confined test cell, formed by driving interlocking sheet pile walls through the contaminated zone into an underlying clay. The test involved the injection and extraction of about four pore volumes (1 pore volume = 7000 L) of a mixture of 80% tert-butanol and 15% n-hexanol. The contaminants were removed by a combination of NAPL mobilization and enhanced dissolution, and the results of postflood soil coring indicate better than 90% removal of the more soluble contaminants (trichloroethane, toluene, ethylbenzene, xylenes, trimethylbenzene, naphthalene) and 70-80% removal of less soluble compounds (decane and undecane). The results of preflood and postflood NAPL partitioning tracer tests show nearly 80% removal of the total NAPL content from the test cell. The field data suggest that a somewhat higher level of removal could be achieved with a longer alcohol injection. IntroductionIt is now known that relatively small nonaqueous phase liquid (NAPL) source zones are capable of producing large contaminated groundwater plumes. While methods such as pumping and treating the contaminated water or funneling the water through reactive walls have been effective for plume control, they do not effectively address the source of the plume. Given that these source zones may continue to release contaminants for many decades or centuries, a large effort is now focused on the development of source zone removal methods. Often these techniques must be applied in situ, owing to the depth of contamination or to the presence of buildings and utilities which prevent excavation. The Rao et al. [1997] field test was performed in an isolated test cell, and it consisted of injecting about nine pore volumes of a 70% ethanol, 12% n-pentanol solution. They reported a bulk NAPL removal of -81%, with a higher removal efficiency for several individual compounds.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe feasibility of creating gas-storage caverns by dissolving carbonate rock formations was examined based on process design, geologic factors, and preliminary economic analysis. The method involves drilling one or more wells, pumping acid into the formation, and then removing and treating the waste fluid. To enhance acid transport into the formation, the rock may be hydraulically fractured prior to pumping the acid.To analyze the requirements for creating storage volume, the following were examined: weight and volume of rock to be dissolved; gas storage pressure, temperature, and volume at depth; solubility of acid-rock reaction products; and acid costs. Design considerations and economic calculations indicate that the new method will be applied most advantageously to carbonate formations deeper than approximately 4000 feet, with limestone at depths between 6000 and 9000 feet preferred. In order to identify potential sites for applying the new method to creating storage volume, a large amount of data from carbonate formations was compiled for six states: Ohio,

Based on aquifer performance tests, 13 out of 15 wells situated at the Mixed Waste Disposal (MWD) area located at the Savannah River site. South Carolina, exhibited high skin factors and low well efficiencies indicative of severely damaged wells. The use of damaged wells in aquifer testing can lead to inaccurate determinations of aquifer properties, and such wells are unusable in future remediation programs. Moreover, damaged wells can go dry during purging, thus compromising sample collection. Pump tests, chemical analyses, and biological investigations revealed that the poor well performance at MWD was attributable to calcite precipitation on the well screen and drilling mud in the filter pack. The calcite problem resulted from improper well installation, and the drilling mud in the filter pack was due to inadequate well development. Experimental rehabilitation procedures employed on two wells, MWD 5A and 1A, included acidification, swabbing, introduction of surfactants, and surging. Treatment of the wells substantially improved well yields, skin factors, and well efficiencies. Moreover, well rehabilitation was determined to be a reasonable alternative to drilling new wells at the MWD wellfield.

No abstract

Reservoir simulation of steam injection into heavy oil sands of West Coalinga Field in California has been conducted to assess suitability of different permeability distributions generated from geological and fractal modeling processes. Permeability distributions in each model were derived by integrating stratigraphically controlled models with core data provided by Chevron Production Company. Three distinct distributions were generated for each lithologic group: facies tract, facies group, and a fractal distribution of the facies group. The grid design is based on stratigraphic architecture of depositional facies. Construction of these models involved application of advanced analytical property-distribution methods conditioned to continuous outcrop control for improved reservoir characterization. Numerical simulation of steam injection into three adjacent 5 spot well configurations was used to assess suitability of each model. Injection and production histories of wells in the study area were simulated, including shutdowns and the occasional conversion of production wells to steam injection wells. The framework provided by the facies groups yielded a more realistic representation of reservoir conditions than facies tracts, which is revealed by a comparison of history-matching results. Permeability distributions obtained using the fractal model predict the high degree of heterogeneity within reservoir sands of West Coalinga Field. Modeling results indicate that predictions of oil production are strongly influenced by the geologic framework and by the boundary conditions. Improved predictions of interwell reservoir heterogeneity have the potential to increase productivity and to reduce recovery cost for California's heavy oil sands, which contain several billion barrels of reserves in the San Joaquin Valley. Introduction The West Coalinga oil field in California (Figure 1) produces from heavy oil sands of the Miocene Temblor Formation. The oil in this field has low API gravity (12º to 15º API) and is highly viscous at the 40ºF initial reservoir temperature. This makes the field an ideal candidate for enhanced oil recovery through steam injection. The field is shallow, multilayered and stratified with low reservoir pressure, varied rock permeability, and an average porosity of about 34%.[1] Steamflooding started in 1961, and Coalinga is the oldest steamflood operation in the state of California. Prior to 1960, only about 10% of the oil in place was produced, but with the advent of steam floods and horizontal drilling, recoverable oil potential has been increased up to approximately 60 to 70%. West Coalinga field was chosen for this study because of the opportunity to relate continuous cores of the producing Temblor Formation to nearby outcrops of the same formation. Observations of lateral variability and vertical sequences in outcrop led to an improved understanding of the geological framework of the reservoir. In particular, detailed characterization of stratigraphic bounding surfaces in outcrops enabled identification of those same surfaces in cores and logs of the reservoir. The bounding surfaces were subsequently used as reference horizons in reservoir modeling.