Yousif K. Kharaka

Aliphatic Acid Anions in Oil-Field Waters--Implications for Origin of Natural Gas

Concentrations of short-chain aliphatic acid anions (acetate, propionate, butyrate, and valerate) in 95 formation-water samples from 15 oil and gas fields in the San Joaquin Valley, California, and in the Houston and Corpus Christi areas, Texas, show three temperature regimes. The sandstone reservoir rocks range in age from Eocene through Miocene. The aliphatic acid anions of formation waters in zone 1 (subsurface temperatures lower than 80°C) are characterized by concentrations less than 60 mg/L and consist predominantly of propionate. The concentrations of aliphatic acid anions in zone 2 (temperatures 80 to 200°C) are much higher (up to 4,900 mg/L) than in zone 1, and decrease with increasing subsurface temperatures and age of their reservoir rocks; acetate forms more than 90% of the total anions. No aliphatic acid anions are believed present in zone 3, which is based on extrapolation of data in zone 2; the temperatures are higher than 200°C. Microbiologic degradation of acetate and dilution by mixing with meteoric water most probably explain the composition and concentration of aliphatic acid anions in zone 1. The trends in zone 2 and the absence of acid anions in zone 3 are explained by thermal decarboxylation of these acid anions as in the reaction: CH3COO- + H2O^rarrCH4 + HCO3-. Aliphatic acid anions generally contribute more than 50% and up to 100% of the measured alkalinity in the samples of zone 2. Their contribution to the alkalinity in zone 1 is small. Iodide concentrations generally increase with increasing concentrations of aliphatic acid anions, which supports the use of iodide as a good proximity indicator of petroleum. The aliphatic acid anions mainly result from the thermocatalytic degradation of kerogen. We believe that these anions, which are highly soluble, are produced and dissolved in the pore waters of the source rocks and are expelled to the reservoir rocks during dehydration of clays. Decarboxylation of these acid anions to the components of natural gas is believed to occur mainly in the reservoir rocks, thus resolving the difficult problem of explaining the primary migration of natural gas. Evidence for the formation of natural gas from decarboxylation of acid anions is provided by the ^dgrC13 values of total bicarbonate and CH4 and the good correlation between the proportions of these anions in formation waters (94% for acetate, 5% for propionate, and 2% for butyrate) and their decarboxylated gases in the natural gas produced (90% for methane, 5% for ethane, and 2% for propane). Calculations show that the amount of gas that can be generated from the decarboxylation of the reported acid anions is large and apparently adequate to produce the amounts of gas in these fields.

Hydrogen and oxygen isotope exchange reactions between clay minerals and water

Abstract The extent of hydrogen and oxygen isotope exchange between clay minerals and water has been measured in the temperature range 100–350° for bomb runs of up to almost 2 years. Hydrogen isotope exchange between water and the clays was demonstrable at 100°. Exchange rates were 3–5 times greater for montmorillonite than for kaolinite or illite and this is attributed to the presence of interlayer water in the montmorillonite structure. Negligible oxygen isotope exchange occurred at these low temperatures. The great disparity in D and O 18 exchange rates observed in every experiment demonstrates that hydrogen isotope exchange occurred by a mechanism of proton exchange independent of the slower process of O 18 exchange. At 350° kaolinite reacted to form pyrophyllite and diaspore. This was accompanied by essentially complete D exchange but minor O 18 exchange and implies that intact structural units in the pyrophyllite were inherited from the kaolinite precursor.

Simultaneous flow of water and solutes through geological membranes-I. Experimental investigation

The relative retardation by geological membranes of cations and anions generally present in subsurface waters was investigated using a high pressure and high temperature ‘filtration cell’. The solutions were forced through different clays and a disaggregated shale subjected to compaction pressures up to 9500 psi and to temperatures from 20 to 70°C. The overall efficiences measured increased with increase of exchange capacity of the material used and with decrease in concentration of the input solution. The efficiency of a given membrane increased with increasing compaction pressure but decreased slightly at higher temperatures for solutions of the same ionic concentration. The results further show that geological membranes are specific for different dissolved species. The retardation sequences varied depending on the material used and on experimental conditions. The sequences for monovalent and divalent cations at laboratory temperatures were generally as follows: Li < Na < NH3 < K < Rb < Cs Mg < Ca < Sr < Ba. The sequences for anions at room temperature were variable, but at 70°C, the sequence was: HCO3 < I < B < SO4 < Cl < Br. Monovalent cations contrary to some field data were generally retarded with respect to divalent cations. The differences in the filtration ratios among the divalent cations were smaller than those between the monovalent cations. The passage rate of B, HCO3, I and NH3 was greatly increased at 70°C.

Short chain aliphatic acid anions in oil field waters and their contribution to the measured alkalinity

Abstract High alkalinity values found in some formation waters from Kettleman North Dome oil field are due chiefly to acetate and propionate ions, with some contribution from higher molecular weight organic acid ions. Some of these waters contain no detectable bicarbonate alkalinity. For waters such as these, high supersaturation with respect to calcite will be incorrectly indicated by thermodynamic calculations based upon carbonate concentrations inferred from traditional alkalinity measurements

Isotopic composition of oil-field brines from Kettleman North Dome, California, and their geologic implications

Abstract Deuterium and O18 analyses were made on 25 formation-water samples from Miocene (Temblor Formation) and Eocene (McAdams Formation) reservoir rocks at Kettleman North Dome oil field, California, and on three surface water samples from Reef Ridge located about three miles to the west of the field. The δO18 values obtained generally increase with depth and most probably are due to temperature controlled exchange reactions with carbonate cement and dissolved carbonate species. The δD values obtained seem to be controlled primarily by the membrane behavior of shales modifying the assumed original values. The contribution of isotopic exchange between water and clays cannot be evaluated at present. The isotopic data support the conclusions based on a detailed study of geology, hydrodynamics, and formation water geochemistry ( Kharaka , 1971) which indicate that: 1. The Temblor Formation waters are probably meteoric in origin concentrated chemically and isotopically by shale membranes, and 2. The McAdams Formation waters were most probably obtained by squeezing the original interstitial marine connate waters of deposition from the underlying Mesozoic sediments.

Chemical Geothermometers Applied to Formation Waters, Gulf of Mexico and California Basins: ABSTRACT

Twelve chemical geothermometers based on the concentrations of silica and proportions of Na, K, Ca, and Mg in water from hot springs and geothermal wells are used successfully to estimate the subsurface temperatures of the reservoir rocks. These 12 geothermometers together with a new geothermometer based on the concentrations of Li and Na were used to estimate the subsurface temperatures of more than 200 formation-water samples from about 40 oil and gas fields in coastal Texas and Louisiana and the Central Valley, California. The samples were obtained from reservoir rocks ranging in depth from less than 1,000 m to about 5,600 m. Quartz, Na-K-Ca-Mg, and Na-Li geothermometers give concordant subsurface temperatures that are within 10°C of the measured values for reservoir temperatures higher than about 75°C. Na-Li, chalcedony, and a modified Na-K geothermometers give the best results for reservoir temperatures from 40°C to 75°C. Subsurface temperatures higher than about 75°C calculated by chemical geothermometers are at least as reliable as those obtained by conventional methods. Chemical and conventional methods should be used where reliable temperature data are required. End_of_Article - Last_Page 588------------

Low to Intermediate Subsurface Temperatures Calculated by Chemical Geothermometers: ABSTRACT

The concentrations of silica and proportions of sodium, potassium, lithium, calcium, and magnesium in water from hot springs and geothermal wells have been combined into 14 chemical geothermometers that are used successfully to estimate the subsurface temperatures of the reservoir rocks. Modified versions of these 14 geothermometers and a new chemical geothermometer, based on the concentrations of magnesium and lithium, were used to estimate the subsurface temperatures (40°C-200°C) of more than 200 formation-water samples from about 30 oil and gas fields located in coastal Texas and Louisiana, Central Valley, California, and North Slope, Alaska. The new Mg-Li geothermometer, which can be used to estimate subsurface temperatures as high as 350°C, is given by t = (1,900/(4.67 + log[(CMg)0.5/CLi]) - 273 where t is temperature (°C) and C is the concentration (mg/L) of the subscripted cation. Quartz, Mg-Li, Na-K-Ca-Mg, and Na-Li geothermometers give concordant subsurface temperatures that are within 10°C of the measured values for reservoir temperatures higher than about 70°C. Mg-Li, Na-Li, chalcedony, and Na-K geothermometers give the best results for reservoir temperatures from 40°C to 70°C. Subsurface temperatures calculated by chemical geothermometers are at least as reliable as those obtained by conventional methods. Chemical and conventional methods should be used together where reliable temperature data are required. End_of_Article - Last_Page 273------------

Subsurface Temperatures Calculated by Chemical Geothermometers Applied to Formation Waters from Northern Gulf of Mexico and California Basins: ABSTRACT

Twelve chemical geothermometers based on the concentrations of silica and proportions of sodium, potassium, calcium, and magnesium in water from hot springs and geothermal wells are used successfully to estimate the subsurface temperatures of the reservoir rocks. These twelve geothermometers together with a new geothermometer based on the concentrations of lithium and sodium were used to estimate the subsurface temperatures of more than 200 formation-water samples from about 40 oil and gas fields in coastal Texas and Louisiana and the Central Valley, California. The samples were obtained from reservoir rocks ranging in depth from less than 1,000 m to about 5,600 m. Quartz, Na-K-Ca-Mg, and Na-Li geothermometers give concordant subsurface temperatures that are within 10°C of the measured values for reservoir temperatures higher than about 75°C. Na-Li, chalcedony, and a modified Na-K geothermometers give the best results for reservoir temperatures between 40°C to 75°C. Subsurface temperatures higher than about 75°C calculated by chemical geothermometers are at least as reliable as those obtained by conventional methods. Chemical and conventional methods should be used where reliable temperature data are required. End_of_Article - Last_Page 1361------------

Organic Acid Anions in Oil-Field Waters and Origin of Natural Gas: ABSTRACT

The concentrations of short-chain aliphatic acid anions (acetate, propionate, butyrate, and valerate) in 120 formation-water samples from 25 oil and gas fields in Alaska, California, Louisiana, and Texas were determined to study the formation of natural gas from decarboxylation of these anions. The reservoir rocks consist of sandstones ranging in age from Triassic through Miocene. The samples from Tertiary rocks depict three temperature zones. The aliphatic acid anions of formation waters in zone 1 (subsurface temperatures < 80°C) are characterized by concentrations less than 60 mg/L and consist predominantly of propionate. The concentrations of acid anions in zone 2 (temperatures 80 to 200°C) are much higher (up to 4,900 mg/L) than in zone 1 and decrease with increasing subsurface temperatures and age of their reservoir rocks; acetate forms more than 90% of the total anions. No acid anions are present in zone 3 (temperatures < 200°C) or in formation waters from Triassic rocks. Microbiologic degradation of acetate and dilution by mixing with meteoric water most likely explains the composition and concentration of acid anions in zone 1. The rend in zone 2 and the absence of acid anions in zone 3 and Triassic rocks are explained by thermal decarboxylation of these anions as in the reaction: CH3COO- + H2O ^rarr CH4 + HCO3-. The aliphatic acid anions mainly result from the thermocatalytic degradation of kerogen. We believe that these anions, which are highly soluble, are produced End_Page 428------------------------------ and dissolved in the pore waters of the source rocks and are expelled to the reservoir rocks during dehydration of clays. Decarboxylation of these anions to the components of natural gas in the reservoir rocks provides a mechanism that does not require the primary migration of natural gas. Evidence for the formation of natural gas from decarboxylation of these acid anions is provided by ^dgrC13 values of total bicarbonate and CH4 and the correlation between the proportions of these anions in formation waters and their decarboxylated gases in the natural gas produced. Calculations show that most of the gas in these fields may have been generated from these anions. End_of_Article - Last_Page 429------------

Stable Carbon Isotopes in Oil-Field Waters and Origin of Carbon Dioxide: ABSTRACT

The ^dgr13C values of dissolved HCO3- in 75 water samples from 15 oil and gas fields were determined in a study of the source of carbon dioxide of the dissolved species and the carbonate cements that modify the porosity and permeability of many petroleum reservoir rocks. The fields are located in the San Joaquin Valley, California, and the Houston-Galveston and Corpus Christi areas of Texas. The reservoir rocks are sandstones ranging in age from Eocene through Miocene. The ^dgr13C values of total HCO3- indicate that the carbon in the dissolved carbonate species and carbonate cements is mainly of organic origin. The range of ^dgr13C values for the HCO3- of these waters is -20 to 28 permit relative to the PDB standard. This wide range of values is explained by three mechanisms. Microbiologic degradation of organic matter appears to be the dominant process controlling the extremely low and high ^dgr13C values (-20 to 28 per-mil) of HCO3- in the shallow production zones where the subsurface temperatures are less than 80°C. The extremely low ^dgr13C values are obtained in waters where the concentration of SO4 is more than 25 mg/L and probably result from the degradation of organic acid anions by sulfate-reducing bacteria (SO42- + CH3COO- ^rarr 2HCO3- + HS-). The high ^dgr13C values probably result from the degradation of acetate by methanogenic bacteria (CH3COO- + H2O^rlarrHCO3- + CH4). For samples from production zones with subsurface temperatures greater than 80°C, thermal decarboxylation of short-chain aliphatic acid anions (principally acetate) to produce CO2 and CH4 is probably the major source of CO2. The ^dgr3C values of HCO3- for waters from zones with temperatures greater than 100°C result from isotopic equilibration between CO2 and CH4. At these high temperatures, ^dgr13C values of HCO3- decrease with increasing temperatures and decreasing concentrations of these acid anions. End_of_Article - Last_Page 479------------