Oilfield Formation Water Research Articles

On the fundamentals of electrochemical corrosion of X65 steel in CO 2-containing formation water in the presence of acetic acid in petroleum production

Electrochemical corrosion behavior of X65 steel in CO 2-containing oilfield formation water in the presence of acetic acid (HAc) was investigated by various electrochemical measurements and analyses as well as thermodynamic calculations of ionic concentrations, reaction rate constants and equilibrium electrode potentials. A conceptual model was developed to illustrate corrosion processes of steel in oilfield formation water system. The anodic reactions of the steel contain a direct dissolution of Fe, Fe → Fe 2+ + 2e, and the formation of corrosion scale, FeCO 3, by Fe + HCO 3 - → FeCO 3 + H + + 2e. The cathodic processes contain the reduction of H +, HCO 3 - , H 2O and HAc, where reduction of HAc has the least negative equilibrium potential and thus dominates the cathodic process. With addition of HAc in the solution, both cathodic and anodic reaction rates increase remarkably. It is attributed to the fact that HAc inhibits or degrades the formation of protective scales due to the decrease of solution pH. Upon electrode rotation, the measured impedance decreases with the increase in HAc concentration. The FeCO 3 scale will not form on electrode surface. When HAc concentration is less than 1000 ppm, the adsorbed intermediate product is not significant, resulting in generation of a low-frequency inductive loop in EIS plots. When HAc concentration is more than 3000 ppm, the adsorption of intermediate product is significant, generating overlapped capacitive semicircles in EIS measurements.

Extended-Range Spectroscopic pH Measurement Using Optimized Mixtures of Dyes

The spectroscopic technique for pH measurement is a well-established laboratory technique that can give high-accuracy pH values. Recent studies have shown the advantage of this technique over standard potentiometric methods for pH measurements in fresh water and seawater and also at high temperatures and pressures. However, a limitation of the spectroscopic technique is that a single pH dye is sensitive only over a narrow pH range. We have developed optimized dye mixtures that are both sensitive and accurate over a broad pH range. The measurement is robust and simple, requires a minimum of two wavelengths, and is independent of the volume of the dye mixture added. Optimization of the dye mixture formulation to maximize accuracy in a broad range of pH involves varying both the dye type and its mole fraction and also accounting for spectral noise. This technique has been successfully applied for in situ pH measurements of oilfield formation waters.

Multiple generations of high salinity formation water in the Triassic Sherwood Sandstone: Wytch Farm oilfield, onshore UK

The origin and heterogeneity of oilfield formation water in the Lower Triassic Sherwood Sandstone at Wytch Farm in the Wessex Basin, UK, have been investigated using production data, detailed water geochemistry and O, S and H stable isotope data. The formation waters are highly saline, NaCl-type brines with TDS values of up to 230,000 mg/L. There is a general decrease in salinity from the flanks of the field to the crest with Cl − decreasing from about 136,000 to 109,000 mg/L. The Cl/Br ratio of the water shows that salinity was largely derived from the dissolution of Upper Triassic continental evaporites found off-structure to the west and north of the field. The water in the field had a meteoric source although variation in δ 2H values suggests that there may be meteoric waters of different ages in the oilfield, reflecting recharge under different palaeoclimatic conditions. At the crest of the field, aqueous SO 4 2 - resulted from dissolution of anhydrite in the reservoir. In contrast, in other parts of the field there is an indication that some of the dissolved SO 4 2 - was derived from oxidation of pyrite at some point on the recharge path of meteoric water to the field. There were two meteoric influx events bringing different Cl − concentrations and different δ 2H values. The first was probably before the Eocene oil influx and could have occurred in the Lower Cretaceous or early Tertiary. The second meteoric influx event probably occurred after or during oil migration into the Wytch Farm structure since the second meteoric water is found at the flanks of the field adjacent to the regions where salt is found in the stratigraphy. The preservation of heterogeneities in oilfield formation water compositions suggests that there has been little aqueous fluid movement or diffusive flux for over 40 million years. Mass flux has been restricted by density stratification within the aquifer and the very low effective permeability for the aqueous phase in the oil-filled reservoir.

Evaluation of soluble benzene migration in the Uinta Basin

AbstractField sampling and mathematical modeling are used to study the long‐distance transport and attenuation of petroleum‐derived benzene in the Uinta Basin, Utah. Benzene concentration was measured from oil and oil field formation waters of the Altamont‐Bluebell and Pariette Bench oil fields in the basin. It was also measured from springs located in the regional groundwater discharge areas, hydraulically down‐gradient from the oil fields sampled. The average benzene concentration in oils and co‐produced waters is 1946 and 4.9 ppm at the Altamont‐Bluebell field and 1533 and 0.6 ppm at the Pariette Bench field, respectively. Benzene concentration is below the detection limit in all springs sampled. Mathematical models are constructed along a north–south trending transect across the basin through both fields. The models represent groundwater flow, heat transfer and advective/dispersive benzene transport in the basin, as well as benzene diffusion within the oil reservoirs. The coupled groundwater flow and heat transfer model is calibrated using available thermal and hydrologic data. We were able to reproduce the observed excess fluid pressure within the lower Green River Formation and the observed convective temperature anomalies across the northern basin. Using the computed best‐fit flow and temperature, the coupled transport model simulates water washing of benzene from the oil reservoirs. Without the effect of benzene attenuation, dissolved benzene reaches the regional groundwater discharge areas in measurable concentration (>0.01 ppm); with attenuation, benzene concentration diminishes to below the detection limit within 1–4 km from the reservoirs. Attenuation also controls the amount of water washing over time. In general, models that represent benzene attenuation in the basin produce results more consistent with field observations.

The Environmental Impact of Oilfield Formation Water on a Freshwater Stream in Nigeria

A comparative analysis of the physico-chemical parameters of treated oilfield formation water and that of a freshwater stream with no previous history of pollution from oil exploration activities was determined. The environmental impact resulting from the discharge of treated oilfield formation water into freshwater samples collected from this stream with no previous history of pollution from oil exploration activities was assessed in terms of changes in water quality parameters such as Dissolved oxygen (DO), Biochemical oxygen Demand (BOD) and in the microbial populations of the freshwater samples over a period of seven days since oilfield formation water readily mixes with flowing water after discharge. The analyses showed that concentrations of constituents such as chloride, total dissolved solids, total hardness, nitrate nitrogen and ammonium nitrogen alkalinity and silicate of the oilfield formation water were much higher than those of the freshwater source. The oxygen uptake (BOD values) in some stations of the freshwater stream differed significantly only at the 5% level after the treatment. Generally, the microbial populations were also lower after the treatment. Such observations suggest that, there is reduction in the biological activities of the freshwater after the addition of the treated oilfield formation water. (Journal of Applied Sciences & Environmental Management: 2003 7(1): 61-65)

Rediscovery of classical methods and their application to the measurement of stable bromine isotopes in natural samples

Isotopic characterisation of bromine could be a powerful tool for the determination of geological processes. However, no analytical procedures have been published to determine bromine stable isotope composition in natural samples, probably due to expected analytical difficulties and the expected similarity with chlorine isotopic compositions, or even because no (signifcant) isotopic fractionation was expected at all. We describe a method for measuring the stable bromine isotope composition in natural samples with a precision of better than 0.18‰. A sample containing 2–5 mg bromide is mixed with K 2Cr 2O 7 and H 2SO 4. This mixture is boiled and during this process Br − is oxidised to Br 2 and distilled, while Cl − is not. Thus chlorine and bromine are separated. The Br 2 is reduced back to Br − and precipitated as AgBr. This is reacted with CH 3I and CH 3Br is formed. The gas mixture is separated by gas chromatography, and the pure CH 3Br is measured by Isotope Ratio Mass Spectrometry. The technique has been tested on a set of natural samples (oil field formation waters) with a known chlorine isotope range between 0‰ and −5‰ SMOC. The bromine isotope range in these sample was found to be between 0‰ and +1.8‰ SMOB, indicating that processes fractionating bromine isotopes are different from those fractionating chlorine isotopes.

Compositional heterogeneities in oilfield formation waters: identifying them, using them

Abstract Two new techniques are now available for gaining information on formation water composition from core samples: core centrifugation, in which preserved core samples, complete with their preserved fluid content, are ultracentrifuged to extract the oil and water; and residual salt analysis (RSA), where salts are redissolved from unpreserved dry core and parameters such as 87 Sr/ 86 Sr are measured in the leachate. These methods are described and details given on the quality control measures that are crucial in order to avoid artefacts of core contamination by drilling fluids. Such methods have allowed formation-water compositional data to be obtained at the sub-metre scale, in some cases revealing significant small-scale variations (gradients and steps) in formation-water chemistry. Resistivity (related to salinity) variations are important for interpretation of water saturation from electrical resistivity logs, which in turn affects the estimate of the total amount of oil contained in the field. In the Machar chalk-reservoired oilfield, formation-water data derived by RSA and core centrifugation both indicate variations in salinity (TDS 140 000–220 000 ppm) that significantly affect resistivity. In some oilfields, assumption of a single resistivity value for the whole field could thus lead to errors in petroleum reserves estimation. Step changes in formation-water composition can be used as indicators of reservoir fluid compartmentalization, important for field development strategy. Examples are given of cases where RSA variations have been used to distinguish between laterally restricted and laterally extensive shales, both in the oil and water legs. Analysis of water compositional variation forms a valuable addition to the range of tools available for assessing reservoir compartmentalization during reservoir appraisal. This is because natural variations in fluid compositions provide quasi-dynamic data (i.e. how fluids have moved slowly during geological time), from which inferences can be made about more rapid fluid-flow patterns under dynamic (oil production) conditions.

Dating and tracing of fluids using 129I and 36Cl: results from geothermal fluids, oil field brines and formation waters

Preliminary results are presented for 129I/I and 36Cl/Cl ratios in formation waters from the KTB project in Germany, geothermal waters from the Salton Sea Geothermal System in California and oilfield brines from the Anadarko Basin in Oklahoma. The results demonstrate the use of these isotopic systems to determine residence times, source formations and pathways of fluids in different geologic situations.

Generation of short chain acid anions in hydrothermally altered sediments of the Guaymas Basin, Gulf of California

An initial investigation of the concentration distribution of short chain organic acid anions in hydrothermally altered sediments of the Guaymas Basin reveals the presence of high concentrations of acetate and propionate relative to normal marine sediments. Acetate and propionate concentrations appear to vary as a function of sediment temperature and reach concentrations 1100 and 200 μm, respectively at temperatures 100°C. As in previously studied oil field formation waters, these acid anions probably play a key role in the generation of CO 2 and hydrocarbons gases, hydrogen ion (pH) buffering, the complexing of aqueous ions, and mineral dissolution and precipatation. At temperatures <100°C these and other acid anions should be important substrates for heterotrophic bacterial processes, including sulfate reduction.

Organic-inorganic reactions during progressive burial: key to porosity and permeability enhancement and preservation

The development of porosity and permeability enhancement and preservation or both in many sandstones is a function of aluminosilicate or carbonate mineral stability. The dissolution of aluminosilicate minerals and subsequent porosity and permeability enhancement is a problem of aluminium mobility. Our experimental data demonstrate that it is possible to increase the mobility of aluminium significantly and to transport it as an organic complex in organic acid solutions. These organic acids, primarily carboxylic and phenolic acids, also have the ability to dissolve carbonate grains and cements. W. W. Carothers &amp; Y. K. Kharaka ( G. cosmochim. Acta 44, 323—332 (1980)) have shown that concentrations of carboxylic acid anions range up to 5000/10 6 (by mass) over a temperature range of 80-100 °C in some oil-field formation waters. Our experiments show that acetic acid solutions at the same concentration and over the same temperature range can increase the solubility of aluminium by one order of magnitude, whereas oxalic acid solutions increase the solubility by three orders of magnitude. Phenols such as hydroquinone and catechol are almost as effective as oxalate. The textural relations observed in the experiments are identical to those in sandstones containing porosity enhancement as a result of aluminosilicate dissolution. A natural consequence of the burial of sedimentary prisms is the maturation of organic material. Nuclear magnetic resonance (n.m.r.) studies have shown that carbonyl and phenol groups are removed from the kerogen molecule before the generation of hydrocarbons. Thermal degradation or the action of mineral oxidants, or both (the reduction of Fe 3+ released from clay diagenesis and the reduction of polysulphides are two examples) may be the mechanisms by which the peripheral groups containing the phenols and carboxylic acids are released from the kerogen molecule. The experiments suggest that the enhancement of porosity in a sandstone as the result of aluminosilicate or carbonate dissolution is the natural consequence of the interaction of organic and inorganic reactions during progressive diagenesis. Because of the time and temperature dependence of these reactions, the actual reaction sequences will be sensitive to the thermal and stratigraphic history of the source reservoir sediments.

Role of Organic and Inorganic Reactions in Development of Secondary Porosity in Sandstones: ABSTRACT

The development of secondary porosity in many sandstones is the result of aluminosilicate and/or carbonate dissolution. The dissolution of aluminosilicates and creation of secondary porosity is a problem of aluminum mobility. Our experimental data demonstrate that it is possible to increase significantly the mobility of aluminum and to transport it as an organic complex in aliphatic acid solutions. The same aliphatic acid solutions have the capability of destroying carbonate cements and debris. Carothers and Kaharka have shown that concentrations of aliphatic acid anions range up to 5,000 ppm over the temperature range 80 to 200°C in some oil field formation waters. Our experiments show that acetic acid solutions at the same concentrations and over the same temperature range can increase the solubility of aluminum by a half an order of magnitude, whereas oxalic acid solutions increase the solubility of aluminum by an order of magnitude. The textural relations observed in the experiments are identical to those observed in sandstones containing secondary porosity as a result of aluminosilicate dissolution. A natural consequence of the burial of sedimentary prisms is the maturation of organic material. These maturation reactions result in the evolution of significant amounts of organic acids and carbon dioxide. The experiments suggest that the development of secondary porosity in a sandstone as a result of aluminosilicate or carbonate dissolution is the natural consequence of the interaction of organic and inorganic reactions during progressive diagenesis. The degree to which secondary porosity develops depends on the ratio of organic to inorganic matter, the sequence, rates and magnitude of diagenetic reactions, fluid flux, and sand/shale geometry. End_of_Article - Last_Page 635------------