裝配圖胡軍雄,裝配,胡軍雄 Impact of modern deepwater drilling and testing fluids on geochemical evaluations Lloyd M. Wenger, , Cara L. Davis, Joseph M. Evensen, James R. Gormly and Paul J. Mankiewicz ExxonMobil Upstream Research Company, P.O. Box 2189, Houston, TX 77252-2189, USA Received 6 October 2003;? revised 1 May 2004;? accepted 1 June 2004.? Guest Associate Editor–Erdem Idiz.? Available online 15 September 2004. Abstract Evaluation of petroleum-fluid properties, hydrocarbon shows, and source-rock characteristics requires new tools to properly recognize and correct for drilling and test-induced contamination, which is increasingly common in modern deepwater field operations. Oil exploration, development, and now production, are more frequently conducted in deeper-water environments where the challenges faced by drilling and operations can severely impact the evaluation of oil and rock geochemistry and fluid properties. Poorly consolidated sediments, swelling clay minerals, and responses to evolving environmental regulations regarding offshore disposal of drill cuttings have resulted in the widespread use of enhanced mineral oil or synthetic-based muds. Also, water-based drilling fluids used in some deepwater operations contain additives that may impact fluid and rock geochemistry. For example, asphalt-based shale stabilizers are added to aid well-bore competency and prevent sticking drill pipe, and polyalkylated glycols are added to depress freezing temperatures and prevent the formation of gas hydrates in the drilling mud. Because these and other additives are often a significant component of water-based muds, they may affect the geochemical signature of fluids and rocks and alter fluid properties. Highly saline brines are another important source of contamination as they are used in completion fluids, water-wet muds, and are emulsified in oil-wet muds. Brine components impact metal contents of petroleum-fluid tests and complicate the determination of formation-water compositions. Despite potential problems introduced by these additives, successful strategies can be devised to accurately access key geochemical and engineering parameters. Article Outline 1. Introduction 2. Drilling fluid components 3. Oil-based drilling fluids: composition and component functions 4. Contamination assessment and correction for oil-based drilling fluids 5. Water-based drilling fluids: composition and component functions 6. Well-test and completion fluids: potential sources of calcium contamination 7. Summary Acknowledgements References 1. Introduction The high costs of drilling, production testing, and facilities construction in deepwater field operations require that high-quality fluid and rock data are acquired for appropriate economic decision-making. Specifically, accurate fluid properties to determine oil quality and value, and reservoir compartmentalization are critical to field evaluation. When source rocks are penetrated, correct characterization of source type, richness and maturity are needed to constrain expected fluid type and properties. However, the rapidly evolving technology necessitated by deepwater drilling and operations has resulted in a spectrum of new contaminants that need to be recognized and either removed prior to sample analysis or corrected for numerically. Drilling muds and completion fluids used in deepwater operations may complicate the interpretation of geochemical and engineering data. Both oil- and water-based muds may impact bulk hydrocarbon fluid properties, geochemical signatures, and source rock properties. Highly saline aqueous fluids, the dominant component of most completion fluids and important components of both water-wet and oil-wet drilling muds, may contribute ionic species that contaminate oil and/or water phases. Accurate well-log analysis requires determination of uncontaminated formation-water salinity and composition. The prevalence of biodegraded hydrocarbon fluids in many deepwater reservoirs has increased interest in naphthenic acid salts (metal naphthenates), which form through interaction of naphthenic acids from biodegraded oils and formation waters and can cause serious oil-quality and scaling problems. Consequently, it is important to recognize contamination effects in both oil and water phases. Representative formation fluid samples are required to evaluate the viability of a discovery or relationship to nearby accumulations. Extent of fluid-test contamination must be determined in order to correct measured fluid properties such as API gravity and gas/oil ratio (GOR), particularly for wireline formation test (WFT) samples. Estimation of additional fluid properties including total acid number (TAN), sulfur, vanadium and nickel contents, and gross compositions (e.g., asphaltene content) may also be important. An estimate of the formation fluid composition is obtained by subtracting the drilling-fluid gas-chromatographic signature, determined by analysis of the mud filtrate, from the contaminated-test signature. Because muds are often re-used, filtrates pressed from actual muds used in each well need to be obtained for reference analyses. This correction technique is calibrated by comparing the properties of uncontaminated drill-stem test (DST) oils with those for contaminated small-volume wireline samples taken from equivalent reservoir zones. Corrections for saturation pressure and live viscosity are less direct, requiring equation-of-state models. The geochemical evaluation of contaminated-fluid tests and shows (e.g., from reservoir sidewall cores) requires a thorough knowledge of the signatures imparted by potential contaminants on all analyses (e.g., GCs, GC/MS). As drilling muds are re-used between wells, it is important to consider the history of the mud and to recognize changes made to the mud system during drilling. Records of the use of additives or changes during drilling are readily determined from drilling operations reports. The list of available additive types and manufacturer specifications is extensive (see summary in World Oil June, 2003). The risk of encountering overpressure while drilling and the need to assure well control has led to a tendency to drill with over-balanced mud-weight systems which often lead to flushing of reservoir fluids from the well-bore vicinity. This can render conventional mud-log hydrocarbon-show evaluation more tenuous and possibly lead to by-passed pay. Although less commonly used in deepwater drilling, water-based mud systems can also significantly impact geochemical evaluations. Extremely high salinity brines (to 300,000+ ppm total dissolved solids) are used to inhibit shale activity in water-wet mud systems and to prevent gas-hydrate formation. Gas hydrates can form in drilling mud under the low temperatures and high pressures encountered in the drill stem and tubulars in deepwater environments. Polyalkylated glycols are added to depress freezing point and inhibit their formation. Contamination in fluid tests requires the development of correction calibrations to estimate the actual fluid properties. Contamination of shale samples by polyalkylated glycols can be difficult to remove, presenting difficulties for the evaluation of source rock potential. Additives based on sulfonated asphalt are also used to inhibit shale activity and promote well-bore stability. Targeted cleaning methods are required to accurately evaluate source-rock samples contaminated with these stabilizers. Following solvent removal of the polar contaminants, organic-richness is determined on solvent-cleaned rock samples and the non-polar extract fraction is characterized for source-rock properties and correlation. Deepwater drilling requirements have led to an increase in the brine salinity used in drilling muds, completion fluids and during production tests. As a result of the prevalence of biodegraded oils in many deepwater environments, and the associated oil-quality and scale formation problems related to naphthenic acids and metal naphthenates, there is an increasing need to recognize “real” from contaminated signatures in fluid tests. The rapidly evolving technology necessitated by deepwater operations has resulted in an increased and changing future role for petroleum geochemistry. 2. Drilling fluid components From a geochemical standpoint, essentially all well samples received for analysis and interpretation have been in contact with drilling and/or completion fluids that include additive contaminants. In order to properly evaluate the effects of these fluids on measured properties, it is necessary to have a complete record of when and why these additives are introduced. Changes to the mud system and additive introduction during drilling are readily determined from drilling-operation reports. Because drilling muds are often re-used, additional forensic investigation may be required, such as which rig and well the mud was used for previously and the types and composition of hydrocarbons encountered. From the drilling or mud engineering viewpoint, all components of the mud system are present for a specific purpose. As shown in schematic diagram (Fig. 1), the inside of a drill pipe is filled with drilling mud, drill cuttings, and any encountered oil, gas, or formation water entering the mud system. The weighting solids (e.g., barite, hematite) are suspended in the continuous phase of the drilling mud, which is either oil- or water-based depending on the wettability requirements of the rock section being penetrated. The discontinuous phase of the mud system (e.g., brine droplets suspended in an oil-based system) must allow critical mud functions (e.g., suppression of swelling clay minerals) without impacting the desired wettability. Emulsifiers allow the discontinuous phase to be incorporated into the continuous phase. Surfactants help maintain wettability during drilling. (50K) Fig. 1.?Schematic of a drill pipe interior, filled with drilling mud, drill cuttings being cleaned away from the bit, and oil, gas, or water from the formation. The mud system lubricates the drill bit and sweeps drill cuttings away. The continuous phase is composed of “oil” or water base. The discontinuous phase, otherwise immiscible, is emulsified for uniform distribution. The engineering purpose of various drilling fluid additives are summarized in the text. 3. Oil-based drilling fluids: composition and component functions A brief discussion of the composition and engineering function of drilling and completion fluid is required to better understand the basis for the use of the various constituents common to deepwater drilling muds and completion fluid systems. Oil-based mud systems are widely used in many deepwater environments, particularly Tertiary delta systems where unconsolidated sediments and swelling clay minerals are common. Generalized distributions of components used in deepwater oil-based mud systems are illustrated in Fig. 2. Components are shown in wt%, excluding weighting agents such as barite. Oil-wet systems contain a mixture of an oil-base fluid and an aqueous-brine fluid in a ratio of approximately 75–25% (±5%). Years ago, oil-based mud almost always referred to a diesel-cut base. Today, offshore oil bases consist of either enhanced mineral oil (EMO, a highly refined, low-aromatic content diesel), or synthetic oil (no aromatic content). The oil phase is dispersed within the aqueous-phase brine through the addition of an emulsifier, typically a calcium fatty-acid soap. The brine in offshore oil-based muds is typically a highly saline calcium chloride solution (commonly 30 wt%). Sodium chloride is sometimes used in deepwater oil-based mud systems, but is not as favorable as calcium chloride due to a lower aqueous solubility. Highly saline brines are particularly desirable in deepwater muds, as the high-ionic strength prevents excessive swelling of clay minerals (activity control). (31K) Fig. 2.?Generalized distributions of components in oil-wet drilling mud fluids in wt%, excluding weighting agents. See text for engineering purpose of various additives. An alkaline pH is typically maintained in oil-based muds by addition of calcium hydroxide. The mud needs to remain alkaline to prevent corrosion of well strings and tubulars and to neutralize acidity introduced by any carbon dioxide or hydrogen sulfide that is encountered. Additional oil-based mud components include additives targeted at filtration control (maintenance of well-bore mud cake and prevention of drilling fluid losses into the formation) and mud rheology (e.g., viscosity, yield point, gel strength). These additives include natural asphalts and gilsonites and specialized amine clay or amine lignite products. 4. Contamination assessment and correction for oil-based drilling fluids Oil-based drilling fluid systems are particularly beneficial in deepwater environments as they do not hydrate active clay minerals and cause them to swell, as can occur in water-based systems. The downside is that most oil-based muds include components with strong physical and chemical similarities to produced oil, complicating the interpretation of geochemical and engineering data. Clean up of oil-based contaminants for source-rock evaluation is straightforward, usually involving washes with organic solvents (e.g., Clementz, 1979; Peters, 1986). There are three basic types of “oil” bases: diesels, EMOs, and synthetics. Representative whole-oil gas chromatograms of each are compared in Fig. 3. (29K) Fig. 3.?Examples of whole-oil gas chromatograms of common oil-wet drilling fluid bases. Diesels include various refinery molecular-weight-range cuts refined from crude oils for fuel. Their composition varies with the original crude composition and the distillation-cut process. Some so-called “dirty” diesels show a broad molecular-weight range and bear a strong resemblance to unrefined crude oils, including significant concentrations of biomarkers. EMOs are basically diesels that have been further refined to remove most aromatic hydrocarbons. EMOs typically contain 1–2% aromatic hydrocarbons with the remainder being saturates. They provide most of the drilling advantages of diesel while meeting offshore regulations for some geographic regions. Synthetics are oil-wet bases that contain double bonds or functional groups promoting environmental breakdown in water. These are usually based on olefins, esters, or mixtures of the two compound classes. The olefin-bases typically have API gravities in the mid-40° range, while esters are in the lower-30° range. There are some drawbacks to their use in drilling, including greater expense and a loss of functionality at extreme temperatures. Synthetics are currently required for offshore drilling in a number of countries, such as the United States, and their overall use is increasing worldwide. Significant strides have been made over the last decade to reduce mud-contamination in WFT tools, notably pump-out modules that allow formation fluids to be pumped through the tool for clean-up prior to sampling (Colley et al., 1992; Smits et al., 1995). Nonetheless, WFTs typically still show some level of mud contamination (Hashem et al., 1999). Fig. 4 compares a clean DST oil to an EMO-contaminated WFT sample from the same reservoir interval and the EMO-base used in the drilling mud. As DSTs typically involve flowing large volumes of oil through the drill stem (100s–1000s of barrels), they very rarely show any overprint of oil-based mud contamination and physical properties such as gravity can be measured directly. DSTs in deepwater are very expensive, however, and often only small volume WFT samples are taken to reduce costs. (32K) Fig. 4.?Comparison of whole oil GCs of uncontaminated DST oil, WFT oil from the same reservoir zone, and the EMO-base used in the drilling mud. The 9.2% EMO contamination in the WFT oil was estimated by GC subtraction (see Section 4 in text). To accurately assess properties of the reservoir oil it is necessary to correct fluid properties measured on the contaminated WFT, which requires an estimation of percent contamination. Percent contamination estimates are based on gas chromatographic analyses of the contaminated fluid and associated mud filtrate, if available. Fig. 4(b) shows a WFT contaminated with the same EMO-base shown in Fig. 4(c). The degree of contamination is determined by subtracting the mud filtrate from the contaminated fluid signature, or, if no filtrate is available, by subtracting the portion of a contaminated chromatogram in excess of a smooth trendline fit for unaltered peaks or for the unresolved complex mixture hump (biodegraded oils). This approach assumes that contaminants are GC-resolvable, an assumption that has been substantiated through analysis of prepared mixtures of clean DST oil with EMO-base, and through addition of and analysis for deuterated tags in the drilling mud. Once the percent contamination is estimated, correcting API gravity, GOR, and fluid volumetrics (e.g., shrinkage or formation-volume factor) is fairly straightforward and is routinely performed by PVT service laboratories. These corrections are based on calibrations developed using experimental mixtures of oil and contaminant (e.g., EMO). Contaminated live-oil viscosity and saturation pressure measurements are more difficult to correct as they require equation-of-state modeling (Gozalpour et al., 2002; Bergman, 2003). Accurate estimation of percent contamination and fluid property correction is most difficult for contaminants with many components indigenous to the oil (e.g., diesel, and to a lesser extent EMO). Synthetics are generally easier to correct for, as olefins and esters are rarely found in uncontaminated crude oils. The geochemical overprint of EMO-mud can be variable. The base-fluid generally represents a narrow molecular-weight-range cut (e.g., C12–C21 in Fig. 4), lacks biomarkers, and has a low concentration of aromatics with a distinctive signature. Drilling muds are often re-used between wells, however, and may become contaminated with crude oil or drilling additives from other wells. Therefore, contaminated oil samples (e.g., WFTs) must be compared to mud-filtrate pressings from the same well, rather than the pure base-oil. An example illustrating the geochemical interpretation of highly contaminated samples is shown in Fig. 5. Only sidewall core (SWC) samples were available for identifying a potential oil rim on a gas reservoir. Because the well was drilled with an over-balanced mud system, the near-well-bore region was heavily flushed by mud and SWCs were all highly invaded with EMO. (45K) Fig. 5.?Evaluation of a possible oil rim at the base of a gas reservoir using contaminated sidewall cores (SWCs). Gas reservoir was highly invaded with EMO due to overbalanced drilling. Gas reservoir SWCs were compared to SWCs and tests from nearby oil reservoirs. Although EMO has low-aromatics (a), distribution of phenanthrene isomers (b) is distinctive. Solvent-extracts of SWCs from the base of the gas reservoir were analyzed and compared to the EMO-mud used, as well as to SWC extracts from nearby reservoirs where oil was tested (DST and WFT oils were also analyzed). A high content of saturates in the gas reservoir extracts confirms extensive EMO contamination due to mud invasion. The DST oil was clean, and the five WFT oils contained EMO contamination between 2% and 18% (Fig. 5(a)). The severe contamination of the SWCs made it difficult to evaluate the presence of indigenous oil. However, despite the fact that aromatic content of the EMO is low, its distinct distribution of phenanthrene isomers allowed discrimination from indigenous oil (Fig. 6). The quality of the oil “show” was assessed from specific phenanthrene ratios, assuming that a gas zone, lacking in