Geoffrey D. Thyne

Predictions of diagenetic reactions in the presence of organic acids

Abstract Stability constants have been estimated for cation complexes with anions of monofunctional and difunctional acids (combinations of Ca, Mg, Fe, Al, Sr, Mn, U, Th, Pb, Cu, Zn with formate, acetate, propionate, oxalate, malonate, succinate, and salicylate) between 0 and 200°C. Difunctional acid anions form much more stable complexes than monofunctional acid anions with aluminum; the importance of the aluminum-acetate complex is relatively minor in comparison to aluminum oxalate and malonate complexes. Divalent metal cations such as Mg, Ca, and Fe form more stable complexes with acetate than with difunctional acid anions. Aluminum-oxalate can dominate the species distribution of aluminum under acidic pH conditions, whereas the divalent cation-acetate and oxalate complexes rarely account for more than 60% of the total dissolved cation, and then only in more alkaline waters. Mineral thermodynamic affinities were calculated using the reaction path model EQ3/6 for waters having variable organic acid anion (OAA) contents under conditions representative of those found during normal burial diagenesis. The following scenarios are possible: 1. 1) K-feldspar and albite are stable, anorthite dissolves 2. 2) All feldpars are stable 3. 3) Carbonates can be very unstable to slightly unstable, but never increase in stability. Organic acid anions are ineffective at neutral to alkaline pH in modifying stabilities of aluminosilicate minerals whereas the anions are variably effective under a wide range of pH in modifying carbonate mineral stabilities. Reaction path calculations demonstrate that the sequence of mineral reactions occurring in an arkosic sandstone-fluid system is only slightly modified by the presence of OAA. A spectrum of possible sandstone alteration mineralogies can be obtained depending on the selected boundary conditions: EQ3/6 predictions include quartz overgrowth, calcite replacement of plagioclase, albitization of plagioclase, and the formation of porosity-occluding calcite cement, smectite, and illite, all of which are commonly documented in rocks. Under some circumstances, OAA-bearing waters are less effective at producing porosity in an arkosic sandstone than are OAA-free waters. In the scenarios modeled in this study the role of OAA in fluid-rock interactions is to contribute to the total alteration assemblage but not necessarily to dominate it, except under exceptional circumstances that might include, for example, hydrocarbon contaminant plumes in aquifers, wetland environments, and within hydrocarbon source-rocks.

Evaluation Of The Effect Of Low Salinity Waterflooding For 26 Fields In Wyoming

This report evaluates the effectiveness of low-salinity waterflooding in the Minnelusa Formation in the Powder River Basin of Wyoming. The Minnelusa sandstone play constitutes a resource of over one-hundred fields with cumulative production of more than 600,000,000 barrels of oil. We conducted initial laboratory screening using Minnelusa oil and rock with synthetic brine, supplemented with geochemical models of low-salinity injection, to evaluate the potential for low-salinity waterflooding in this formation. The laboratory experiments showed little or no incremental recovery from low-salinity injection. Calculation and comparison of recovery factors for 51 Minnelusa reservoirs were used to further evaluate the effectiveness of low-salinity waterfloods at the field scale. There was no increase in recovery for fields that used low salinity injection (26) compared to fields with mixed or formation water injection (25). Since some Minnelusa fields have relatively fresh formation water, the amount of dilution was quantified using the salinity ratio (SR), defined as the ratio of salinity of injected water to salinity of formation water. This analysis showed that while some fields actually had little or any salinity reduction (13), the remaining fields with significant dilution (38) still showed no correlation between dilution and recovery factor. Since some postulated mechanisms involve change in wettability, injection of low-salinity water may produce later water breakthrough. Analysis of water breakthrough timing and watercut evolution for 23 fields found no significant difference between fields with low-salinity injection and mixed-water or saline injection. Introduction Low-salinity waterflooding has been widely studied during the last decade by various research groups as one of the most inexpensive methods of enhanced oil recovery (EOR). The level of investigation into low-salinity waterflooding has sharply increased in the past three years as more research groups have become involved (Webb et al. 2008, Alotaibi and Nasr_el_Din 2009, Austad et al. 2010, Boussour et al. 2009, Cissokho et al. 2009, Kumar et al. 2010, Lager et al. 2008, Patil et al. 2008, Seccombe et al. 2008, Pu et al. 2010, Rivet et al. 2010, RezaeiDoust et al. 2010, Gamage and Thyne 2011). Laboratory studies with synthetic formation water, reservoir and outcrop rocks and reservoir oil have been conducted with injected water diluted by a factor ranging from 2.5 to 100-fold compared to formation water. Many studies have reported increases in recovery of 2-30% original-oil-in-place (OOIP) varying with brine and crude oil compositions and rock types used. However, while both laboratory and field studies have had successful results, there are also examples in which low-salinity flooding does not create additional production (Sharma and Filoco 2000, Rivet et al 2010, Skrettingland et al. 2010). The fundamental observations of increased recovery from low-salinity flooding in the laboratory were made by Martin (1959) and Bernard (1967). This work was extended and brought to wider attention by various workers over the last 15 years (Jadhunanadan and Morrow 1995, Zhou et al. 1995a, Zhou et al. 1995b, Tang and Morrow 1997, Yildiz et al. 1999, Morrow et al. 1998, Tang and Morrow 1999a, Tang and Morrow 1999b, Maas et al. 2001, Robertson et al. 2003, Lohardo et al. 2008, Morrow et al. 2008, Pu et al. 2008, Kumar et al. 2010, Pu et al. 2010). The mechanism(s) is still a matter of debate (Austad et al. 2010, Kumar et al. 2010, Lee et al. 2010, RezaeiDoust et al. 2010, Sorbie 2010), but continued work shows diluting the salinity of injected water can often produce increased oil recovery. However, there are few field studies (Webb et al. 2004, McGuire et al. 2005, Robertson 2007, Seccombe et al. 2008, Lager et al. 2008, Seccombe et al. 2010, Skrettingland et al. 2010) and scaling laboratory results to the field is always challenging. Currently, laboratory tests are used to screen candidate reservoirs followed by single well tracer tests before implementation

Joint Sustainability of Petroleum Energy Production and Water Resources

We all agree on the urgent need to develop solar, wind, and biofuel energy resources, but this editorial is not about alternative energy. We should first admit that all of us depend on petroleum energy consumption. We drive to work, heat our houses, fly to conferences or to vacations on sunny beaches, and buy goods from the grocery store. However, we also face an economic imperative to reduce consumption, particularly our reliance on foreign oil and gas. As our petroleum reserves decline, energy companies are focusing on development of natural gas and unconventional reserves such as oil shale and coalbed methane. Development of these resources will consume significant amounts of water and generate large volumes of water that require treatment. Many of the most promising unconventional deposits are in the western United States and Canada, where water resources are scarce. Thus, the joint sustainability of petroleum-energy production and water resources has emerged as an evermore important technical challenge. As hydrogeologists, we are interested in the sustainability of our water resources. As citizens, hydrogeologists care about the sustainability of our energy resources. Oil and gas professionals have the same interests but a fundamentally different perspective on water. Water is viewed as a waste product from petroleum production and is not historically associated with water resources. This view is woven into business models and regulatory structures. As hydrogeologists, we recognize the environmental, social, regulatory, and legal limitations of this view. Fortunately, joint sustainability of oil and gas energy and water is within our grasp. However, to achieve this sustainability, we must overcome complex technical and regulatory issues. For example, coalbed methane extraction requires dewatering coalbeds, units that are often interbedded with aquifers. The shortand long-term effects of large withdrawals from coalbeds on hydraulically connected aquifers and associated streamflow are often not considered, let alone quantified rigorously. Produced water is disposed of rather than reclaimed, usually by surface discharge or infiltration, without much regard to the watershed hydrology. This ‘‘waste product’’ can be nearly potable to saline water that could be used beneficially with appropriate treatment. What if we were to treat this ‘‘waste’’ as a resource? What if we were to recognize and actively manage the interactions of the entire system, including both water and energy resources? This approach requires overcoming many hurdles besides professional perspectives. For instance, produced water, ground water, and natural resources are typically regulated by separate governmental agencies. It is not clear which laws take precedence when they suggest conflicting requirements. Current watershed models do not include consideration of subsurface processes related to energy extraction nor do current energy extraction models consider impacts on overand underlying aquifers and streams. Legal or regulatory precedents often result in use of simple screening models for water resources assessment rather than rigorous hydrologic modeling now commonly used by hydrogeologists. Thus, education of the public, energy companies, judges, attorneys, and regulators on the current best practice for water resources assessments needs to be a priority. The optimum outcome requires comprehensive and integrated water management planning that provides for energy-related extraction, reclamation of produced water, or disposal that minimizes undesirable watershed impacts. Oil shale development presents a similar challenge. While the extraction technology is not fully developed, all proposed methods require significant amounts of water and will produce considerable volumes of wastewater. In situ retorts have an unknown impact on ground water quality. Much of the water must come from the Upper Colorado River basin, which supplies seven western states and Mexico. Thus, integrated hydrologic assessments must be performed to ensure future sustainability of water for energy production, development, and natural resources. For both technologies, models should be developed that can estimate the watershed-scale effects on water quantity and quality. Technology for treating coproduced water for environmental, industrial, or residential use should be developed concurrently with production technologies. A reasoned approach would integrate water resource assessment with energy exploration and production. Surface and ground water modeling conducted jointly with reservoir engineering studies can steer drilling that balances the optimal hydrocarbon production and minimizes disturbance to water resources. In the meantime, policy makers should construct modern guidelines that recognize beneficial use of coproduced water. Water policies inconsistent with joint sustainability must be revisited. Joint research programs in energy-water sustainability should be a priority of funding agencies. Perhaps most importantly, transparent, honest discussions must begin among energy professionals, policy makers, regulators, legal experts, water-resources professional, and stakeholders. We are all citizens who depend on the joint sustainability of water and energy resources.