Venoco, Inc. was a company engaged in hydrocarbon exploration. It primarily operated in the Monterey Formation in California. In 2017, the company filed bankruptcy and was liquidated.
Developments in microbial-enhanced oil recovery (MEOR) have made huge advancements over the last few years. A new programmatic approach to MEOR is organic oil recovery (OOR), the management of the microbial ecology to facilitate the release of oil from the reservoir. Using this breakthrough process, which does not require microbes to be injected, over 180 applications have been conducted between 2007 and 2011 in producing oil and water-injection wells in the United States and Canada. This chapter reviews the OOR process, a summary of results and two case studies in detail.
Abstract The Montalvo field has produced 42 million barrels of oil from the 3000 foot thick non-marine fluvial Sespe formation. Pressure transient analysis suggests that individual reservoirs are less than 200 feet in width and have limited connectivity. Since detailed mapping of individual sands is virtually impossible, early development was focused on the bigger sand packages. This case study presents the methodology to pick stepout locations and evaluate bypassed reservoirs in a field that has produced for over 60 years. With as many as 200 small-scale reservoirs at Montalvo, conventional structure and net pay maps are of limited use when picking locations. Venoco used a stochastic approach that identifies deposition trends with models that varied channel width, length, sinuosity, orientation and facies. Issues addressed include the lack of a common oil-water contact, significant variations in reservoir pressures, and transmissibility of faults. The geologic model was populated with over 1000 realizations then reduced to 133 by history matching fluid production and reservoir pressures in a dynamic model. An objective function was then used to pick the best 30 realizations for prediction runs. The authors concluded it was unrealistic to expect the model to predict recovery from individual wells, but it could identify trends and rank locations. Drilling results have confirmed this conclusion, with a wide variation in performance of the eight wells drilled since 2010 and an average estimated ultimate recovery (EUR) very close to predictions. The methodology is especially relevant where operators hope to increase recovery in fields with a long production history, poor data resolution, multiple horizons and/or significant variation of reservoir quality. This work shows that it is possible to use reservoir modeling to identify oil reservoirs on a scale smaller than seismic resolution.
Summary Using a breakthrough process, which does not require microbes to be injected, more than 100 microbial enhanced-oil-recovery (MEOR) treatments were conducted from 2007 to the end of 2010 in oil-producing and water-injection wells in the United States and Canada. On average, these treatments increased oil production by 122%, with an 89% success rate. This paper reviews the MEOR process, reviews the results of the first 100+ treatments, and shares what has been learned from this work. Observations and conclusions include the following: Screening reservoirs is critical to success. Identifying reservoirs where appropriate microbes are present and oil is movable is the key. MEOR can be applied to a wide range of oil gravities. MEOR has been applied successfully to reservoirs with oil gravity as high as 41° API and as low as 16° API. When microbial growth is appropriately controlled, reservoir plugging or formation damage is no longer a risk. Microbes reside in extreme conditions and can be manipulated to perform valuable in-situ "work." MEOR has been applied successfully at reservoir temperatures as high as 200°F and salinities as high as 140,000 ppm total dissolved solids (TDS). MEOR can be applied successfully in dual-porosity reservoirs. A side benefit of applying MEOR is that it can reduce reservoir souring. An oil response is not always observed when treating producing wells. MEOR can be applied to many more reservoirs than thought originallys with little downside risk. This review of more than 100 MEOR well treatments expands the types of reservoirs in which MEOR can be applied successfully. Low-risk and economically attractive treatments can be accomplished when appropriate scientific analysis and laboratory screening are performed before treatments.
This study was based on the detergent properties of microemulsions on crude oil-contaminated soils. Were used as the ionic surfactant sodium dodecyl sulfate (SDS) and sodium dodecyl benzene sulfonate (SDBS). Kerosene was used as the oil phase, and as additives, 1-pentanol and 1-butanol. Microemulsions as systems were evaluated on a soil contaminated with oil from the Yaracal district, Falcon State. The systems evaluated were put in contact with soil, shaking mechanically for 04 hours. The microemulsion with SDS, was found to be the highest performance, with 95.43 %, a result confirmed by infrared spectroscopy technique, which were characterized with soil samples before and after treatment with the systems surfactants-oil-water. This procedure can be an alternative remediation for areas affected by oil spills, and can even be applied in cleaning oil in various solid substrates.
Using a breakthrough process, which does not require microbes to be injected, over one hundred Microbial Enhanced Oil Recovery (MEOR) applications have been conducted since 2007 in producing oil and water injection wells in the United States and Canada. On average, these applications increased oil production by 127% with an 89% success rate. This paper reviews the MEOR process, reviews the results of the first one hundred plus applications and shares what has been learned from this work. Observations and conclusions include the following: 1. Screening reservoirs is critical to success. Identifying reservoirs where appropriate microbes are present and oil is movable is the key. 2. MEOR can be applied to a wide range of oil gravities. MEOR has been successfully applied to reservoirs with oil gravity as high as 41° and as low as 16° API. 3. When bacteria growth is appropriately controlled, reservoir plugging or formation damage is no longer a risk. 4. Microbes reside in extreme conditions and can be manipulated to perform valuable in-situ “work.” MEOR has been applied successfully at reservoir temperatures as high as 200°F and salinities as high as 140,000 ppm TDS. 5. MEOR can be successfully applied in dual-porosity reservoirs. 6. A side benefit of applying MEOR is that it can reduce reservoir souring. 7. An oil response is not always seen when treating producing wells. The application of MEOR can be applied to many more reservoirs than originally thought with little downside risk. This review of more than a hundred MEOR applications expands the types of reservoirs where MEOR can be successfully applied. Low risk and economically attractive treatments can be accomplished when appropriate scientific analysis and laboratory screening is performed prior to treatments. Introduction From July 2007 through the end of 2010, there have been one hundred and six applications of MEOR to enhance recovery of North American waterfloods in a programmatic approach to organic oil recovery. The application of this process typically consists of five steps: 1) initial field screening, 2) well sampling and laboratory analysis, 3) In-situ Microbial Response Analysis (ISMRA), where the nutrient formula developed in the laboratory is applied to a producing well to assure the microbial response under field conditions replicates lab results, 4) pilot testing (if applicable) in a representative portion of the waterflood and 5) full-field application. Thirty-eight treatments have been applied to thirty-five producing wells and sixty-eight treatments have been applied to thirty injection wells. From the results available to date, on average, the wells and their adjacent producers have seen an oil production increase eighty-nine per cent of the time. On average, these applications have resulted in a 127% increase from pre-treatment rates to post-treatment maximum rates. Table 1 shows the results available as of January 1, 2011.
