William W. Carothers

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.

Experimental oxygen isotope fractionation between siderite-water and phosphoric acid liberated CO2-siderite

The equilibrium fractionation of O isotopes between synthetic siderite and water has been measured at temperatures ranging from 33° to 197°C. The fractionation between siderite and water over this temperature range can be represented by the equation: 103 ln α = 3.13 × 106T−2 − 3.50. Comparison between the experimental and theoretical fractionations is favorable only at approximately 200°C; at lower temperatures, they generally differ by up to 2 permil. Siderite was prepared by the slow addition of ferrous chloride solutions to sodium bicarbonate solutions at the experimental temperatures. It was also used to determine the O isotope fractionation factors between phosphoric acid liberated CO2 and siderite. The fractionation factors for this pair at 25° and 50°C are 1.01175 and 1.01075, respectively. Preliminary results of the measured C isotope fractionation between siderite and Co2 also indicate C isotopic equilibrium during precipitation of siderite. The measured distribution of 13C between siderite and CO2 coincides with the theoretical values only at about 120°C. Experimental and theoretical C fractionations differ up to 3 permil at higher and lower temperatures.

Thermal decarboxylation of acetic acid: Implications for origin of natural gas

Abstract Laboratory experiments on the thermal decarboxylation of solutions of acetic acid at 200°C and 300°C were carried out in hydrothermal equipment allowing for on-line sampling of both the gas and liquid phases for chemical and stable-carbon-isotope analyses. The solutions had ambient pH values between 2.5 and 7.1; pH values and the concentrations of the various acetate species at the conditions of the experiments were computed using a chemical model. Results show that the concentrations of acetic acid, and not total acetate in solution, control the reaction rates which follow a first order equation based on decreasing concentrations of acetic acid with time. The decarboxylation rates at 200°C (1.81 × 10−8 per second) and 300°C (8.17 × 10−8 per second) and the extrapolated rates at lower temperatures are relatively high. The activation energy of decarboxylation is only 8.1 kcal/mole. These high decarboxylation rates, together with the distribution of short-chained aliphatic acid anions in formation waters, support the hypothesis that acid anions are precursors for an important portion of natural gas. Results of the δ13C values of CO2, CH4, and total acetate show a reasonably constant fractionation factor of about 20 permil between CO2 and CH4 at 300°C. The δ13C values of CO2 and CH4 are initially low and become higher as decarboxylation increases.

Stable carbon isotopes of HCO3- in oil-field waters-implications for the origin of CO2

Abstract The δ 13 C values of dissolved HCO 3 − in 75 water samples from 15 oil and gas fields (San Joaquin Valley, Calif., and the Houston-Galveston and Corpus Christi areas of Texas) were determined to study the sources of CO 2 of the dissolved species and carbonate cements that modify the porosity and permeability of many petroleum reservoir rocks. The reservoir rocks are sandstones which range in age from Eocene through Miocene. The δ 13 C values of total HCO 3 − indicate that the carbon in the dissolved carbonate species and carbonate cements is mainly of organic origin. The range of δ 13 C values for the HCO 3 − of these waters is −20–28 per mil relative to PDB. This wide range of δ 13 C values is explained by three mechanisms. Microbiological degradation of organic matter appears to be the dominant process controlling the extremely low and high δ 13 C values of HCO 3 − in the shallow production zones where the subsurface temperatures are less than 80°C. The extremely low δ 13 C values ( 4 2− are more than 25 mg/l and probably result from the degradation of organic acid anions by sulfate-reducing bacteria ( SO 4 2− + CH 3 COO − → 2 HCO 3 − + HS − ). The high δ 13 C values probably result from the degradation of these anions by methanogenic bacteria ( CH 3 COO − + H 2 O ai HCO 3 − + CH 4 ). Thermal decarboxylation of short-chain aliphatic acid anions (principally acetate) to produce CO 2 and CH 4 is probably the major source of CO 2 for production zones with subsurface temperatures greater than 80°C. The δ 13 C values of HCO 3 − for waters from zones with temperatures greater than 100°C result from isotopic equilibration between CO 2 and CH 4 . At these high temperatures, δ 13 C values of HCO 3 − decrease with increasing temperatures and decreasing concentrations of these acid anions.

Hydrogeochemistry of Big Soda Lake, Nevada: An alkaline meromictic desert lake

Big Soda Lake, located near Fallon, Nevada, occupies an explosion crater rimmed by basaltic debris; volcanic activity apparently ceased within the last 10,000 years. This lake has been selected for a detailed multidisciplinary study that will ultimately cover the organic and inorganic hydrogeochemistry of water and sediments because the time at which chemical stratification was initiated is known (~1920) and chemical analyses are available for a period of more than 100 years. Detailed chemical analyses of the waters show that the lake is at present alkaline (pH = 9.7), chemically stratified (meromictic) and is extremely anoxic (total reduced sulfur—410 mg/L as H2S) below a depth of about 35 m. The average concentrations (in mg/L) of Na, K, Mg, Ca, NH3, H2S, alkalinity (as HCO3), Cl, SO4, and dissolved organics (as C) in waters of the upper layer (depth 0 to 32 m) are 8,100, 320, 150, 5.0, < 0.1, < 0.5, 4,100, 7,100, 5,800, and 20 respectively; in the deeper layer (depth 37 to 64 m) they are 27,000, 1,200, 5.6, 0.8, 45, 410, 24,000, 27,500, 6,800, and 60, respectively. Chemical and stable isotope analyses of the waters, δ13C and Δ14C values of dissolved total carbonate from this lake and surface and ground waters in the area together with mineral-water equilibrium computations indicate that the waters in the lake are primarily meteoric in origin with the present chemical composition resulting from the following geochemical processes: 1. (1) evaporation and exchange with atmosphere, the dominant processes, 2. (2) mineral-water interactions, including dissolution, precipitation and ion exchange, 3. (3) inflow and outflow of ground water and 4. (4) biological activity of macro- and microorganisms, including sulfate reduction in the water column of the deeper layer at a very high rate of 6.6 μmol L−1 day−1.

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------------

Isotope geochemistry of minerals and fluids from Newberry volcano, Oregon

Isotopic compositions were determined for hydrothermal quartz, calcite, and siderite from core samples of the Newberry 2 drill hole, Oregon. The δ15O values for these minerals decrease with increasing temperatures. The values indicate that these hydrothermal minerals precipitated in isotopic equilibrium with water currently present in the reservoirs. The δ18O values of quartz and calcite from the andesite and basalt flows (700–932 m) have isotopic values which require that the equilibrated water δ18O values increase slightly (− 11.3 to −9.2‰) with increasing measured temperatures (150–265°C). The lithic tuffs and brecciated lava flows (300–700 m) contain widespread siderite. Calculated oxygen isotopic compositions of waters in equilibrium with siderite generally increase with increasing temperatures (76–100°C). The δ18O values of siderite probably result from precipitation in water produced by mixing various amounts of the deep hydrothermal water (− 10.5 ‰) with meteoric water (− 15.5 ‰) recharged within the caldera. The δ13C values of calcite and siderite decrease with increasing temperatures and show that these minerals precipitated in isotopic equilibrium with CO2 of about −8 ‰. The δ18O values of weakly altered (<5% alteration of plagioclase) whole-rock samples decrease with increasing temperatures above 100°C, indicating that exchange between water and rock is kinetically controlled. The water/rock mass ratios decrease with decreasing temperatures. The δ18O values of rocks from the bottom of Newberry 2 show about 40% isotopic exchange with the reservoir water. The calculated δ18O and δD values of bottom hole water determined from the fluid produced during the 20 hour flow test are −10.2 and −109‰, respectively. The δD value of the hydrothermal water indicates recharge from outside the caldera.

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------------

Geochemistry of Oil-Field Waters from Northern Gulf of Mexico Basin: ABSTRACT

End_Page 478------------------------------Detailed chemical analyses of 120 formation-water samples from 25 oil and gas fields in coastal Texas and Louisiana show that the salinity of water in the geopressured zones ranges from about 10,000 to 270,000 mg/L dissolved solids and may be higher or lower than the salinity of water in the overlying normally pressured zones. All the waters are of the Na-Cl type; Na generally constitutes more than 90% of the total cations and Cl constitutes more than 90% and up to 99.8% of the total anions. Ca concentrations increase with increasing salinity and bicarbonate increases with decreasing Ca concentrations. Magnesium and sulfate concentrations are generally low. The concentrations of copper, lead, and other heavy metals are generally less than 10 µg/L. Hydraulic fluid potentials and ^dgrD and ^dgr18O values indicate that the formation waters are most probably modified connate waters representing the original marine water of deposition. The chemistry of these waters, however, is markedly different from that of ocean water. The differences in composition are shown to result from (1) interaction of the waters with evaporites, (2) interaction of the waters with minerals and organic matter present in the enclosing sedimentary rocks, and (3) membrane-squeezing and membrane-filtration properties of shales. End_of_Article - Last_Page 479------------