资源目录
压缩包内文档预览：
编号：22018685
类型：共享资源
大小：5.91MB
格式：ZIP
上传时间：2019-09-16
上传人：QQ24****1780
认证信息
个人认证
王**（实名认证）
浙江
IP属地：浙江
50
积分
- 关 键 词：
-
电机
机电
启动
速度
控制
节制
cad
- 资源描述：
-
电机启动与速度控制带CAD图,电机,机电,启动,速度,控制,节制,cad
- 内容简介：
-
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 EditorErdem Idiz. Available online 15 September 2004. AbstractEvaluation 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 Outline1. 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 References1. IntroductionThe 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 componentsFrom 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 functionsA 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 7525% (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 fluidsOil-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 12% 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 (100s1000s 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., C12C21 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 indigenous aromatics, would show only an EMO-dominated phenanthrene signature. On this basis, SWCs through nearby oil reservoirs ranged from good (phenanthrene ratios matched oil tests) to no-show (possibly a non-reservoir zone between oil horizons or completely flushed by mud). SWCs from the base of the gas reservoir showed an EMO-dominated phenanthrene signature, consistent with a lack of indigenous oil (Fig. 5(b). This evidence, plus the dry, biogenic character of the gas (based on molecular and isotopic compositions) indicated that there was no oil rim at the base of the gas reservoir. (55K) Fig. 6.Aromatic GC/MS scans from Fig. 5 example. Combined ion chromatograms for m/z 178 (phenanthrene), m/z 192 (methyl phenanthrenes), m/z 206 (C2-phenanthrenes), and m/z 220 (C3-phenanthrenes) are displayed. Distributions are very different between indigenous oil (uncontaminated DST) and EMO-mud, which allows identification of in situ oil in highly invaded SWCs. 5. Water-based drilling fluids: composition and component functionsThere has been a trend toward the use of higher salinity brines in both water and oil-based mud, because they allow superior activity control for swelling-prone clay minerals. The generalized composition of offshore and onshore water-based muds is shown in Fig. 7. The continuous phase is typically potassium or sodium chloride brine. Calcium chloride brines, used for the discontinuous phase of oil-based muds, are specifically avoided as a continuous phase because they adversely impact mud viscosity and fluid loss. (31K) Fig. 7.Generalized distribution of components in water-based drilling muds (in wt%, excluding weighting agents). For onshore drilling operations, diesel often serves as the discontinuous phase of water-based muds because of its improved drilling properties. The potential presence of diesel in such muds is important to consider when evaluating the geochemistry of onshore oils and rocks. Bentonite clays and gels are the predominant viscosifiers in water-based muds. Lignosulfonates and lignite coals are added for filtration control. Lignite may impact geochemical interpretation of SWC and cuttings extracts, as it imparts an immature signature to saturate biomarker distributions. Water-based muds are kept alkaline with sodium hydroxide. The calcium hydroxide favored in oil muds is not used because of problems associated with calcium in water-based systems. Finally, a wide variety of “polymers” are used in water-based muds to address an array of potential drilling problems. In the past, water-based mud systems imparted few contaminants to impact geochemistry and fluid properties. Today, water-based mud systems, especially those used in the deepwater with additives to control swelling clays and gas hydrate formation, can significantly complicate geochemical interpretations. A whole-extract gas chromatogram of a deepwater source-rock penetration from a well drilled with water-based mud is shown in Fig. 8. The initial straight-hole well was lost due to sticking drill pipe as a result of encountering active, swelling clays. To get the sidetracked well down, a shale-stabilizer additive, based on sulfonated asphalt, was used in the water-based mud. As a result, all SWC and cuttings samples were contaminated. An important objective of this well was to evaluate source characteristics and hydrocarbon potential. However, source evaluation was significantly compromised by the sulfonated-asphalt additive, which had a total organic-carbon content of approximately 35 wt% and a Rock-Eval hydrogen index of about 600 mgHC/gTOC. (24K) Fig. 8.Whole extract GC of source-rock SWC contaminated with sulfonated asphalt additive used in water-based mud as a shale stabilizer. The high TOC and hydrogen index of the additive interfere with source evaluation and must be cleaned up prior to analysis. The problem was solved by exploiting the polarity of the contaminant for clean up. SWCs were solvent-extracted with dichloromethane (DCM) and then subjected to liquid chromatography. The high polarity of the sulfonated asphalt allowed it to be completely removed from the rock by DCM extraction. Liquid chromatography (LC) allowed for separation of indigenous saturate and aromatic hydrocarbons from the sulfonated-asphalt additive. The broad, multiple-peaked character of S2-pyrograms from Rock-Eval analyses of contaminated samples were reduced after cleaning, suggesting that TOC and Rock-Eval hydrogen index values determined on the solvent-extracted rocks were valid. Biomarker analyses were conducted on the cleaned saturate and aromatic hydrocarbon LC fractions. As a result, source rock-to-oil correlation and vertical source-rock variability were constrained. Although they did not appear to impact the TOC, Rock-Eval or biomarker signatures, other organic contaminants added to the water-based mud used in this well, including polyglycerols, xanthan biogum, starch, and polyanionic cellulose, could potentially impact other organic geochemical analyses. Water-based mud was also used in a second deepwater well from this area. Drilling problems meant that fluid tests (e.g., WFTs) could not be taken. Oil shows were recovered from the mud pit, but were highly contaminated by a water-based additive (Fig. 9). Potential source rocks were penetrated but were also highly contaminated. The nature of the contaminant had to be determined to accurately evaluate fluid properties and source potential. (19K) Fig. 9.Whole oil GC of oil-stained mud collected from mud pit. Polyaklylated glycols were added to the water-based mud to prevent gas hydrate formation. Glycols interfere with both extract/oil analysis and source rock screening (TOC, Rock-Eval). Glycols can be removed from saturate and aromatic fractions, but are difficult to fully remove from source rock samples. The contaminant was determined to be polyalkylated glycol. Glycols are added to water-based muds used in deepwater wells as “anti-freeze” to prevent the formation of solid gas hydrates through freezing-point depression. In order to correct fluid properties measured on glycol-contaminated samples, a calibration for hydrocarbon-glycol mixtures would have to be made. These calibrations were not carried out because of the effort required, and consequently uncertainties still remain about reservoir fluid properties. An attempt was made to clean rock samples for source rock analyses using DCM-extraction followed by liquid chromatography. While liquid chromatography yielded clean saturate and aromatic fractions for biomarker analyses, even multiple DCM extractions of the rock samples could not remove all glycol compounds, probably due to strong bonding with the clays. Rock-Eval data, in particular, still appeared to be highly compromised. Although not attempted in this situation, Barnard et al. (2001) report that satisfactory Rock-Eval data can be obtained when polyalkylated glycol contamination is removed using a polar solvent mix of methanol, acetone and water. When a third deepwater well was drilled in the same area, oil-based (EMO) mud was used. There were no significant difficulties with the drilling of this well and fluid property and geochemical interpretations were relatively straightforward. Although geochemists have traditionally complained about the use of oil-based mud and advocated drilling with water-based systems, these examples suggest that times have changed. Oil-based mud systems are actually preferable now to water-based, as they generally have a more predictable and correctable impact on fluid properties and geochemistry. 6. Well-test and completion fluids: potential sources of calcium contaminationMany recent deep-to-ultra-deepwater oil discoveries are biodegraded. This is a function of shallow reservoir depths, low geothermal gradients, and cooling effects of large water columns (Wenger et al., 2002). Biodegraded oils tend to be relatively acidic, with high TAN (e.g., Robbins, 1998; Olsen, 1998; Meredith et al., 2000) and high CO2 contents in solution gas (Wenger et al., 2002). Due to the hydrophilic nature of the carboxylic acid group, organic acids (especially naphthenic acid) tend to concentrate near the oil-water contact. Naphthenic acids formed during biodegradation can complex with metal cations from formation water to form naphthenate salts that act as natural surfactants (Goldszal et al., 2002a and Goldszal et al., 2002b). Metal naphthenates may partition into oil- or water-phases depending on the system pH. In the oil-phase, naphthenates deteriorate oil-quality and value as they can cause corrosion and must be removed or stabilized prior to refining. In the water-phase, naphthenates can result in serious scale-deposition problems in separators, de-salters and topside facility tubulars, disrupting production operations. Calcium naphthenate is particularly insidious, as it is mutually soluble in both oil and water under typical reservoir production conditions. Its presence promotes tight emulsions that require additional processing, severely impacting deepwater development economics. During production, changes in separator pH can lead to localized scaling (Rousseau et al., 2001). Depressurization or an increased water-cut during production can lead to additional CO2-release, impacting pH (Dyer et al., 2003) and intensifying scaling problems through the production string. Although naphthenate salts have not received much attention in geochemical literature, they are widely recognized in engineering literature as the cause for severe scale problems in West Africa and Venezuela (Rousseau et al., 2001), the North Sea (Vindstad et al., 2003), and Indonesia (Gallup et al., 2002). Calcium in oil is a refining problem that impacts the use and consequently the value of biodegraded oils. Calcium content of oil is typically monitored at the refinery as part of the crude assay analysis. High organic-calcium contents translate to high-ash contents. High-Ca, high-ash oils can not be cracked to suitable fuel oil for power plants as they can damage power turbines. Low-Ca, low-ash oils, even if they are heavily biodegraded, are commonly used for this purpose. Consequently, calcium content is closely monitored and high-Ca oils typically incur heavy debits. Although organically bound, oil-associated calcium is the primary cause of refining problems that lead to decreased oil value. However, some of the measured calcium in DST oils may represent calcium contamination from completion brines emulsified with the oil-phase. The example summarized in Fig. 10 shows high calcium contents measured by refinery assays for a set of DST oils. If the high calcium contents were “real”, representing primary petroleum compositions, significant oil-value debits and additional processing and facilities costs would be incurred. If they could be identified as contamination (from DST completion fluids), large oil-value debits and additional processing facilities would be avoided, significantly improving development economics. (26K) Fig. 10.Calcium content as a function of test type and processing. Several DST oils had high original calcium contents. By centrifuging prior to analysis, calcium content was significantly reduced. Analyses of separated water phase indicated contamination by CaCl2 completion fluid used in the DST procedure (a). WFT samples are relatively uncontaminated. Comparison of samples from the same reservoir by test type and processing protocol (b) show the magnitude of contamination in DST samples. High calcium contents in two severely biodegraded WFTs appear to represent “real” organic calcium. Both DST and WFT samples, many of which came from the same reservoir in the same well, were analyzed to assess potential calcium contamination. Samples were centrifuged first in an attempt to separate any emulsified water from the biodegraded oil, a step not traditionally taken prior to refinery assay. Both oil and water phases were analyzed. Chloride content of the oil samples was measured by X-ray fluorescence (XRF) to assess amount of emulsified water remaining. Calcium and other cations were measured on both oil and water phases by inductively coupled plasma-atomic emission mass spectroscopy (ICP-AES). Results indicate the bulk of calcium in the DST oils could be separated by centrifuging (Fig. 10(b). WFT samples from equivalent zones had very low calcium contents. Analyses of the water phase separated from DST oils indicated a composition representing pure calcium chloride brine (as used in completion fluids), not natural formation water. These results showed that most of the calcium in the original DST oils were related to contamination from completion fluids (300,000 ppm calcium-chloride brine used as a cushion in the well-bore prior to the initiation of the DST flow). Only two WFT oils from the same well, both severely biodegraded, appeared to contain significant levels of organic calcium (Fig. 10(a), no DST was taken in this well). These oil reservoirs were not under consideration for development, due to the presence of oil with very low API gravity, high viscosity and high TAN. As a follow-up, all DST oils collected from this region are now routinely subjected to a multi-stage water-washing/centrifuge step followed by ICP and XRF-analyses. Primary (“real”) organic calcium is that remaining after essentially all chloride has been removed. Although DST oils showed the bulk of the calcium contamination due to their interaction with pure (300,000 ppm) CaCl2 completion brines, WFT oils could also have minor levels of calcium contamination. Although never in contact with completion fluids, WFTs from this area are contaminated with 220% of the EMO drilling mud used (estimated by method described in Section 4). The EMO-based mud includes calcium from discontinuous phase CaCl2 brines, Ca(OH)2 added for alkalinity and a small amount from fatty acid soaps (see Fig. 2). The water phase of the EMO-mud only represents 25% of the total fluid, and EMO contamination in the WFT oils is less than 20%, so calcium contamination in WFTs is probably not significant. This is supported by the fact that calcium contents in the WFT samples were not significantly reduced by centrifugation prior to analysis. 7. SummaryObservations and conclusions of this work are as follows: 1. Modern deepwater drilling and completion fluids can significantly impact geochemical and fluid property data.2. Accurate evaluation of contaminated fluids and rocks should involve analysis of the drilling fluid, from the mud filtrate if possible, and the contaminated sample. Sometimes this requires analysis of both oil- and water-phases.3. In some cases, contaminated samples can be cleaned up, or data can be mathematically corrected.4. Biodegraded oils in deepwater reservoirs are associated with a number of components (e.g., acids and naphthenates) that bring new challenges to development and production engineering (emulsions, scale) and refining (corrosion, ash). An understanding of the chemistry, physical properties and interaction of indigenous and operation-added materials is critical to mitigating the economic impact of such oils.AcknowledgementsThe authors thank the management of ExxonMobil Upstream Research Company for permission to publish this work. ExxonMobil colleagues Marty V. Smith (drilling fluids), Gordon L. Kornfeld (fluid testing), Winston K. Robbins (naphthenic acids and naphthenates), and W. Lee Esch (water chemistry) are gratefully acknowledged for subject matter input and productive discussions. Core Laboratories Pencor Division is acknowledged for assistance in method development for wireline oil test percent contamination corrections. GeoChem Laboratories, Inc. assisted in development of the sulfonated asphalt removal procedure. Critical reviews of the manuscript by Ted Bence, Marc D. Norman, Brad J. Huizinga, two anonymous reviewers, and editorial handling by Guest Associate Editor Erdem Idiz improved the manuscript, are appreciated. ReferencesBarnard et al., 2001 Barnard, P., Cutler, I., Van Grass, G., Mills, N., 2001. The effects of drilling fluid composition on the quality of geochemical data. In: 20th International Meeting on Organic Geochemistry, Nancy, France, 1014 September, Abst., pp. 521522. Bergman, 2003 Bergman, D., 2003. Oil base drilling muds characterization and EOS modeling. In: The Petroleum
- 温馨提示:
1: 本站所有资源如无特殊说明，都需要本地电脑安装OFFICE2007和PDF阅读器。图纸软件为CAD,CAXA,PROE,UG,SolidWorks等.压缩文件请下载最新的WinRAR软件解压。
2: 本站的文档不包含任何第三方提供的附件图纸等，如果需要附件，请联系上传者。文件的所有权益归上传用户所有。
3.本站RAR压缩包中若带图纸，网页内容里面会有图纸预览，若没有图纸预览就没有图纸。
4. 未经权益所有人同意不得将文件中的内容挪作商业或盈利用途。
5. 人人文库网仅提供信息存储空间，仅对用户上传内容的表现方式做保护处理，对用户上传分享的文档内容本身不做任何修改或编辑，并不能对任何下载内容负责。
6. 下载文件中如有侵权或不适当内容，请与我们联系，我们立即纠正。
7. 本站不保证下载资源的准确性、安全性和完整性, 同时也不承担用户因使用这些下载资源对自己和他人造成任何形式的伤害或损失。
人人文库网所有资源均是用户自行上传分享，仅供网友学习交流，未经上传用户书面授权，请勿作他用。
川公网安备: 51019002004831号