Thomas L. Dunn

Experimental study on water-rock interactions during CO2 flooding in the Tensleep Formation, Wyoming, USA

Abstract The conditions for mineral alteration and formation damage during CO2 treatment of Tensleep sandstone reservoirs in northern Wyoming, USA, were examined through core-flooding laboratory experiments carried out under simulated reservoir conditions (80°C and 166 bars). Subsurface cores from the Tensleep sandstone, which were cemented by dolomite and anhydrite, and synthetic brines were used. The brines used were (Ca, Mg, Na)SO4–NaCl solution (9.69 g/l total dissolved solids) for Run 1 and a 0.25 mol/l NaCl solution for Run 2. The solution used in Run 1 was saturated with respect to anhydrite at run conditions, which is characteristic of Tensleep Formation waters. Three major reactions took place during flooding, including (1) dissolution of dolomite, (2) alteration of K-feldspar to form kaolinite, and (3) precipitation (in Run 1) or dissolution (in Run 2) of anhydrite. All sample solutions remained undersaturated with respect to carbonates. The permeability of all the cores (except one used in Run 2) decreased during the experiments despite the dissolution of authigenic cement. Kaolinite crystal growth occurring in pore throats likely reduced the permeability. Application of the experimental results to reservoirs in the Tensleep Formation indicates that an injection solution will obtain saturation with respect to dolomite (and anhydrite) in the immediate vicinity of the injection well. The injection of NaCl-type water, which can be obtained from other formations, causes a greater increase in porosity than the injection of Tensleep Formation waters because of the dissolution of both dolomite and anhydrite cements.

Predictive models for sandstone diagenesis

Abstract Factors governing the evolutionary path that sandstone and shale sequences follow during burial diagenesis include: provenance and depositionally-controlled compositional and textural elements; near-surface redox reactions; organic-inorganic interactions within the zone of intermediate burial diagenesis; deep diagenetic reactions, which include abiotic, thermal sulfate reduction, carbonate mineral alteration and quartz cementation; and, the potential for meteoric influx and renewal of near-surface processes due to uplift, exposure and/or base level fluctuation. As a consequence, the use of thermal exposure indicators to describe the extent of diagenesis, such as R0, or time-temperature history indicators, such as TTI, must be used with caution. Though useful in predicting general trends in porosity loss due to simple compaction, they have little utility in making forward predictions of anomalously-high porosity (e.g. preserved and/or enhanced porosity), or anomalously-low porosity. A more useful approach, whereby the processes controlling porosity evolution are evaluated in terms of the depositional, hydrologic, burial and thermal histories, is presented here.

Cation Geothermometry and the Effect of Organic-Inorganic Diagenetic Reactions

Predicted cation ratio geothermometry temperatures using equations of Na K Na K Ca Mg Na K Ca and Mg Li were compared between oilfield and geothermal settings Geothermometers in oilfield waters yielded less consistent temperature predictions compared to geo thermal waters in the same temperature range Scatter of predicted temperature in oilfield waters is greatest in the temperature interval where carboxylic acid anions CAAs are in greatest concentration CAAs are not present in geothermal systems Temperature prediction improves in those oilfield waters where CAAs are present and account for less than 80 of total alkalinity The assumptions of cation ratio geothermometry are violated to varying degrees in oilfield waterswhere CAAs are abundantThese assumptions are 1 cation ratios are controlled by exchange between solid aluminosilicates However CAAs affect mineral solubility by forming complexes with the cations Therefore the ratios of cations in solution differ from those values expected when cation exchange between aluminosilicate minerals is the only control on thecation ratios Furthermore concentrations of Ca and Mg are strongly controlled by carbonate equilibria which in turn is strongly affected by the presence of CAAs 2 aluminum is conserved in solid phases However CAAs form stable complexes with AI increasing AI silicate solubility and mobilizing AI thus AI may not be conserved in mineral phases 3 neither H nor CO enter into the net reactions ie pH is buffered by aluminosilicate hydrolysis However acetate the dominant CAA found in oilfield waters is an effective buffer of pH in feldspathic rocks Also at higher temperatures decarboxylation of CAAs increases the PCO2 of oilfield waters The consistently worse temperature prediction of cation ratio geothermometers in oilfield waters in the 80 120oC temperature range is another

Cements and In-Situ Widths of Natural Fractures, Almond Formation, Green River Basin, Wyoming

Abstract In-situ fracture width and extent of cementation are evaluation characteristics useful in the exploration and development of naturally fractured reservoirs. A joint field test of the Amoco Champlin No. 254B-2H, a horizontal well in the Almond Formation at the northern extent of the Echo Springs Field, Green River Basin, Wyoming, provided an opportunity to examine natural fracture cementation histories and widths at in-situ pressures using slant and horizontal cores. In this field, natural fractures in the Mesaverde Group provide increased production rates and ultimate recoveries of natural gas. Conventional core plug samples were taken from this well so as to orient the trace of natural fractures parallel to the plug axis. These samples were epoxy impregnated at an effective horizontal pressure of 2500 psi, representative of reservoir conditions. Polished thin sections were used to image the in-situ fracture widths using back-scattered scanning electron microscopy. The fracture cementation includes quartz overgrowths locally followed by sparse kaolinite cement. Patchy barite cement followed kaolinite. Sparry calcite was the latest mineralization. Both barite and calcite prop open the fractures; quartz and kaolinite do not. In-situ fracture width (both open and mineralized) measurements were collected perpendicular to the length of the fracture traces. Average widths range from 59 to 118 μm (micrometers). Apparent one-inch plug permeabilities can be calculated from open fracture widths, and range from 297 md to 3108 md. In-situ fracture permeabilities of this magnitude should provide high rates of production if the fractures are numerous, have extensive areal dimension, and are not plugged with either natural cements or drilling and completion fluids. Borehole imaging of the sampled well indicates numerous fractures at a spacing of one to two meters, yet production rates are less than the production anticipated from the calculated permeability. Since both this study and borehole imaging indicate the presence of open fractures at in-situ conditions, then either the areal extent of the fractures is limited or the fracture apertures have been reduced during drilling and completion or by the presence of natural cements.