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Abstract A methodology to determine water contamination levels prior sampling to guarantee the capture of representative water samples, as its highly crucial for understanding saturation profile, reservoir reserves & field development planning. The presence of low salinity mud while trying to sample low salinity water adds further challenges in acquiring a clean sample. Especially, that the resistivity measurement sometimes won't have a resistivity contrast. Nevertheless, the conventional optical density measurement won't be able to differentiate the two water types. Applying power law model and utilization of resistivity/conductivity and density measurements to quantify contamination levels as the fluid property in miscible filtrate & formation water will match such transition profile. Since both water base mud filtrate (WBMf) & formation water exhibit the same optical spectroscopy response, it will be quite challenging to differentiate between them. Hence, the above method is used to quantify accurate contamination. The pH measurement was also used to monitor rate of change & stabilization across pump out station whenever there's no contrast in salinities between WBMf & formation water. The contamination calculations process can be divided into four steps: Firstly, exponent selection for the power law which depends on the inlet selection, either radial probe or single probe. Secondly, determination of filtrate properties (initial end point). Third, flow regime identification diagnostics after power law fitting. Fourth, end point extrapolation. The resistivity/conductivity, density and pH measurements were utilized during down hole fluid analysis of water stations to evaluate the contamination levels using the power law model in a shallow carbonate environment. The model was tried for multiple inlets radial probe & single probe using different power law exponents. The results were consistent and determined the right timings to sample clean water bottles with minimum contamination levels to be analyzed at the lab. Hence, providing accurate geochemical analysis for the reservoir's field development planning and optimizing station time and avoiding unnecessary pump out in real time which saves time and cost.
- Asia > Middle East > Saudi Arabia (0.47)
- North America > United States > Texas (0.28)
- North America > United States > Montana > Sheridan County (0.24)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
- (2 more...)
Abstract Primary emulsifiers are an integral part of an invert emulsion (water in oil) oil based mud system. These are a class of long chain fatty acids and their derivatives. Primary function of an emulsifier in invert emulsion invert emulsion oil based mud system is to minimize the interfacial tension (IFT) between water and oil to have a stable emulsion which is an important quality of oil based mud. Water droplets are surrounded by these long chain fatty acids like an encapsulation. Fatty acids have hydrophilic head group and hydrophobic head group. The hydrophilic end groups are in contact with the surface of water droplets while the hydrophobic tail groups extend into oil phase thereby forming an osmatic cell. Only water can pass through the osmatic cell wall but not salts. Tall oil fatty acid (TOFA) are the most widely used commercially available emulsifiers which shows excellent emulsion stability even at harsh conditions such as high temperature and high pressure. TOFA is a by product of paper industry. Vegetable oil is also a good source of fatty acids present in the form of triglycerides of saturated and unsaturated fatty acids of varying carbon chain lengths. Our focus on this work is to utilize the abundant availability of used cooking/vegetable oil available for the application of emulsifier by chemical modification. A comparative study has been carried out by formulating invert-emulsion OBM using commercially available emulsifier and the emulsifier derived from used cooking/vegetable oil. The performance of emulsifier developed from waste vegetable oil has been discussed in detail.
Current State and Future Trends of Wireline Formation Testing Downhole Fluid Analysis for Improved Reservoir Fluid Evaluation
Ramaswami, S. R. (Shell International Exploration and Production B.V.) | Cornelisse, P. W. (Shell International Exploration and Production B.V.) | Mooijer, M. (Shell International Exploration and Production B.V.) | Kim, I. (Shell International Exploration and Production B.V.) | Elshahawi, H. (Shell International E&P) | Dong, C. L. (Shell International E&P)
Abstract The introduction of downhole fluid analysis (DFA) two decades ago was a major addition to the wireline formation testing suite of measurements previously available in the industry, both in real-time to optimize the sampling operations and to provide additional fluid measurements as an integral component of integrated fluid property interpretations. The progression from basic measurements such as fluid resistivity to advanced optical analysis has paved the way for much improved definition of reservoir fluids, including the variation of fluids within reservoirs. Downhole Fluid Analysis is a continuously evolving field, so we will begin this paper by looking back at the evolution and application of various types of sensors for operational real-time decision making as well as post-operational fluid evaluation. We will then highlight current capability gaps, focusing on the need for improved real-time contamination monitoring in some environments of interest and our desire to measure additional fluid properties and specific species concentrations.
- Asia (1.00)
- North America > United States > Texas (0.92)
- Europe (0.67)
- Geology > Geological Subdiscipline > Geochemistry (0.93)
- Geology > Mineral (0.68)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Flow Modeling and Comparative Analysis for a New Generation of Wireline Formation Tester Modules
Kristensen, Morten (Schlumberger) | Ayan, Cosan (Schlumberger) | Chang, Yong (Schlumberger) | Lee, Ryan (Schlumberger) | Gisolf, Adriaan (Schlumberger) | Leonard, Jonathan (Schlumberger) | Corre, Piere Yves (Schlumberger) | Dumont, Hadrien (Schlumberger)
Abstract Wireline formation testing (WFT) is an integral part of reservoir evaluation strategy in both exploration and production settings worldwide. Application examples include fluid gradient determination, downhole sampling, fluid scanning in transition zones, as well as interval pressure transient tests (IPTTs). Until recently, however, formation testing was still challenging and prone to failure when testing in low-mobility, unconsolidated, or heavy-oil-bearing formations, especially with single-probe type tools. A new-generation WFT module with a 3D radial probe expands the operating envelope. By using multiple fluid drains spaced circumferentially around the tool, the new module can sample in tighter formations and sustain higher pressure differentials while providing mechanical support to the borehole wall. We performed a detailed flow modeling-based analysis of the contamination cleanup behavior during fluid sampling with the new module. Using both miscible (sampling oil in oil-based mud) and immiscible (sampling oil in water-based mud) contamination models we studied the cleanup behavior over a wide range of formation properties and operating conditions. Comparison of the cleanup performance of the new module with the performance of conventional single-probe tools demonstrates that the new module is 10 to 20 times faster than the single-probe tools when sampling in tight formations. Finally, we also compared the new module against the sampling performance of dual packers and a focused probe. This work is directly relevant to the planning and fundamental understanding of wireline fluid sampling. The key contributions are miscible and immiscible contamination cleanup models that include the effect of tool storage, a comprehensive analysis of contamination cleanup behavior for the new-generation WFT module with comparisons against conventional single-probe, focused probe, and dual-packer tools, and a characterization of fluid sampling conditions versus the preferred type of sampling tool. Introduction A logical start for any wireline formation testing (WFT) operation is a tool string design that considers the formation evaluation objectives and expected formation and fluid properties. With the current availability of an arsenal of probes having different shapes, focused probes of circular or elongated design, and dual packers, this planning stage has now become a more complex process. The recently introduced 3D radial probe (Al Otaibi et al. 2012; Flores de Dios et al. 2012) adds another choice for the engineers in planning WFT surveys.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
Abstract Knowing the exact mineralogical composition of the formation sand is very important for well treatment designs. Acidizing treatments are designed with various concentrations and mixtures of acids, depending on the composition and concentration of carbonate minerals, such as calcite, dolomite, siderite, and ankerite, in the formation. Accurately identifying carbonate systems in the presence of clay minerals (i.e., muscovite, illite, kaolinite, chlorite, smectite, and mixed layer) and feldspars (i.e., albite and microcline) is always a challenge. To meet this challenge, X-ray diffraction (XRD) analyses based on Rietveld and external standard methods have been widely used to determine the mineralogical compositions of samples. But accuracy of the results depends on various factors, such as the crystalline nature of the sample, the presence of an amorphous inorganic phase, and the presence of organic materials. Sample preparation, sample packing, and even human error in phase identification are also factors responsible for inaccuracy in compositional study. This paper describes an attempt to enhance the accuracy level in analyzing formation samples containing clays, feldspars, carbonates, and quartz with the help of combined analytical methods, such as XRD, thermal gravimetric analysis (TGA), and acid solubility. Some differences were observed during the initial XRD study of the samples and acid solubility data, and the differences were greater with increased concentrations of clay and feldspars in the sample. Hence, for better calculation of carbonate minerals present in the sample, the result from TGA was taken into account. The results derived from TGA were shown to be in line with the solubility data. Final interpretation was drawn on the basis of the combined data obtained from XRD, TGA, and the solubility analysis. For confirmation, the resulting filtrate from the acid solubility test was analyzed using the inductively coupled plasma (ICP) method, and the output data helped in calculating the final concentration of soluble components. Introduction Previous studies (Nanda et al. 2011) reveal good comparative results between TGA, XRD, and acid solubility data in cases of carbonate stones (calcite and dolomite). When this method was applied to formation samples containing carbonates in the presence of clay and feldspars, some deviation was observed between the XRD results and the acid solubility data. Some formation (shale) sand samples were received from a field location for characterization and evaluation of mineral composition, and the samples showed deviations in the results for acid solubility and XRD study, indicating soluble phases. According to composition studies from XRD, the samples were mixtures of chlorite, calcite, dolomite, feldspars, clay, and quartz. Among these, chlorite, calcite, and dolomite should have been soluble in dilute hydrochloric (HCl) acid. Weight loss as a result of the acid soluble contents should have been in line with chlorite and carbonates (calcite and dolomite). But in this case, deviations were observed, which could have been a result of errors in calculating the soluble phases by XRD in the presence of feldspars and clays, as there were too many peaks to consider. So, for confirmation, an XRD study was also conducted on the samples after an acid solubility test, which showed wiped off calcite, dolomite, and chlorite peaks. To obtain an actual quantification of carbonates in the presence of a soluble chlorite phase, a TGA was performed on the samples in the temperature range of 400 to 950°C (Gunasekaran and Anbalagan 2007). The TGA revealed the weight loss was caused by carbon dioxide formation of calcium/magnesium oxide from the calcite and dolomite phases. These data were back calculated to obtain the calcite and dolomite content in the samples. The calcite and dolomite content obtained from TGA data was added to the chlorite content for the acid soluble phases.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (1.00)
- Geology > Mineral > Silicate > Tectosilicate > Feldspar (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (0.76)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.69)
- Well Completion > Acidizing (0.69)
- Reservoir Description and Dynamics > Formation Evaluation & Management (0.55)
Advanced Formation Testing and PVT Sampling in Deep Gas Condensate Reservoir: Case Study from Malaysia
Minhas, Haq Nawaz (Petronas Carigali Sdn Bhd) | Fakharuddin, Muhamad (Petronas Carigali Sdn Bhd) | Gibrata, Muhammad Antonia (Petronas Carigali) | Bt M Nordin, Norbashinatun Salmi (Petronas Carigali) | Cheong, Boon Cheng (Schlumberger) | Daungkaew, Saifon (Schlumberger) | Sinnappu, Suresh (Schlumberger)
Abstract Downhole sampling in gas condensate reservoir is well known to be challenging due to the nature of the near critical fluids. Reservoir fluid properties can change dramatically with slightly changes in reservoir pressure and temperature. As a result, accurate and representative PVT data are essential for reservoir fluid modeling and field development purpose. This paper presents the first downhole gas condensate sampling in a deep gas condensate field, offshore East Malaysia. Samples collected from the previous surface tests showed large variation in Condensate Gas Ratio (CGR), from 50 to 200 stb/mmscf. This resulted in large uncertainty in the dew point pressure, condensate yield, reservoir fluid productivity, and also reservoir fluid typing, i.e. rich or lean gas condensate reservoirs. As a result, there are strong needs to acquire high quality downhole samples to reduce these uncertainties, which may affect the entire field development plan. This paper illustrates several key challenges in this particular case study; for example, the risk of stuck tools required us to minimize stationary time during clean up process. Typically in the same area, the usual time allowed per station is less than 2 hours. However, since this gas condensate sampling job is much more complex in its fluid behaviour than other types of reservoir fluids, the wireline formation tester tool were allowed to be slightly longer at each station. Furthermore, best possible downhole fluid samples were requested for PVT modeling. As a result, minimizing OBM contamination and controlling drawdown pressure drop in low mobility reservoir were added into operation challenges. The use of new technology Wireline Formation Tools (WFT) such as focused sampling probe and in-situ fluid analyzer were introduced to ensure that job objectives can be met with limited time per station. The focused sampling approach was used to collect representative PVT sampling in several stations. The direct comparison between conventional and focused sample probes in the same zone will also be presented in this paper. During the pump-out period, the guard and sampling flowline pump rates were controlled and pressure drop between each flowline was monitored closely in the real time to ensure that the clean single phase reservoir gas is flowing though the sample flowline. When the clean gas condensate with minimum OBM contamination is detected from different measurements such as stabilized GOR, live density and composition using the in-situ fluid analyzer tool, PVT samples were collected at each station. It seems like the focused sampling technique procedure is straight forward. However, when different types of mud, i.e. WBM and OBM, was used in different hole sections, the two-phase flowing behaviour, i.e. gas condensate in OBM and in WBM behave differently, and therefore, this two-phase flowing effect requires different operation procedures for this particular reservoir in such a limit time frame.
- Asia > Malaysia (0.86)
- North America > United States > Texas (0.28)
Abstract Fluid identification is an important objective to resolve key uncertainties of a complex reservoir prior to perforation in the developed fields of Eastern Kalimantan. This paper explains how using a formation tester equipped with two downhole fluid analyzer modules helped understand reservoir fluid characteristics, identify production zones and optimize perforation zone selection. Relying only on open hole log data and performing correlations among nearby wells may be inconclusive since the channel sands under study have limited lateral extent and hard to correlate. Several layers are potential pay zones and may contain oil or gas. However, water zones and secondary gas cap formation in a few layers are also common. Nonetheless, unexpected fluid production, such as water or excessive gas is an undesirable outcome. A formation tester equipped with an extra large diameter probe and two downhole fluid analyzer modules was used to identify reservoir fluids in newly drilled wells. Two fluid analyzers were placed above and below the downhole pump module. The fluid analyzers monitored downhole oil based mud filtrate contamination, free gas presence, water or oil flow at selected depths. The surveys identified the downhole fluids and clarified oil, gas and water bearing zones. Some zones were identified to have gas and possible oil presence. Few stations, which were clearly identified as oil were perforated and produced oil/dry oil with natural flow. The survey helped optimize perforation zone selection, avoided unwanted fluid production and helped the operator to find and produce oil in a complex setup. Introduction In developed and ageing fields, it is essential to understand the reservoir and fluid characteristics for optimum reservoir management. A common method is to integrate all existing information on reservoir rock, fluid and production data. These range from seismic, geological and petrophysical data, core analysis, well tests and production data. However in complex reservoirs, despite the number of wells drilled in a development scenario, correlating / integrating such data is not always enough to avoid unexpected results. Missing productive intervals in a new well, zones with unexpectedly low / high pressures, undesirable fluid production and presence of additional reserves or bypassed hydrocarbons are common occurrences in complex reservoirs. At a given location, layer or compartment, reservoir fluids may change with time; water encroachment, secondary gas cap formation/gas cap expansion, reservoir re-pressurization are some of the reasons of changing fluid characteristics. For certain fluids, pressure decline causes thermodynamic changes (such as solids precipitation or significant liquid dropout) which can significantly alter well productivity, ultimate recovery and project economics. In aging reservoirs, fluid movements are of constant focus and routine cased hole logs are common to track such changes. Location of news wells for bypassed/remaining oil is equally important. In certain environments, conventional open hole logs may not fully resolve the fluid content of stacked reservoirs. In Kalimantan, Indonesia, it is common to have low resistivity pay zones which can contain significant amount of hydrocarbons. Also, the well known density-neutron separation may not always result in water free hydrocarbon production. Coupled with reservoir and fluid complexities above, often zones with unwanted fluids are perforated. Selectively testing each producing layer to identify fluids using conventional surface test equipment is a viable approach but can be costly. In this paper, direct pressure and fluid identification measurements using a wireline formation tester (WFT) tool will be outlined. The Modular Formation Dynamics Tester (MDT)* tool and its downhole fluid analysis methodology using Live Fluid Analyzer (LFA)* and Composition Fluid Analyzer (CFA)* were used in the ageing Sangatta field. The main objective was to clearly identify fluids downhole and give conclusive results on detecting water, gas and oil zones and oil bearing formations with a secondary gas cap. Several zones were identified with WFT were later perforated and tested. Well test results following WFT surveys from four wells are presented.
- Asia > Indonesia > Kalimantan (0.82)
- North America > United States > Texas (0.68)
- Asia > Indonesia > East Kalimantan > Makassar Strait (0.26)
Abstract Residual oil estimations are mainly based on special analysis of representative core samples (SCAL). In high recovery oil fields, where remaining oil saturations approach residual oil saturations, it is possible to test these estimations using Pulsed Neutron Decay (PND) logging to monitor water saturation changes. Such monitoring techniques can identify inconsistencies, leading to possible adjustments in recovery strategies and eventual improvements in ultimate recovery. The recovery strategy for As Sarah oilfield in Libya has been based on SCAL. PND logging in producing wells has generally confirmed forecast saturations and only slight adjustments to the initial strategy have been necessary to achieve a recovery factor greater than 40% at the end of the plateau phase. However, recent infill drilling allowed for the first time an investigation of recovery efficiency in swept, but previously un-drilled, parts of the reservoir. Higher than expected, the remaining oil saturations lead to the suspicion that cased hole saturation logs in producing wells may underestimate overall reservoir oil saturations. In order to enhance understanding of the recovery process a research program was undertaken to investigate the true, post aquifer sweep, remaining oil saturation. Included in this program are: special core investigations using preserved and restored state core material; analysis of pore size distribution and fluid typing through nuclear magnetic resonance (NMR) measurements; surface and downhole analysis of oil composition verses depth; and finally, a program of production and injection testing to monitor oil saturation changes in a new well, aquifer swept, zone. The planning and first results of this program are presented in this publication, including available field data. It is expected that the program, once complete, will lead to a better understanding of the depletion mechanism and help improve ultimate recovery of As Sarah field. Some of the methodologies described in this paper may be of general interest in the effort to optimise the recovery of hydrocarbons. Field Description The large onshore As Sarah oil field, discovered in 1989, is located in the Sirte basin of eastern Libya. As Sarah field is estimated to contain over 1Billion bbl STOIIP. Present production from As Sarah is around 90,000 BOPD and is nearing the end of its plateau phase. As Sarah field structure is a northward dipping fault-block, bounded by a major fault to the south. Internal fault compartments are common throughout the field and are in communication. A roughly north-south trending major fault divides the field into eastern and western zones, each with distinct saturation pressures. Observed only in the western part of the field are "tar-mats", comprising 10–20ft thick, highly viscous, oil layers; simulation has confirmed that these tar-mats adversely affect vertical reservoir connectivity. The reservoir comprises clean, fluvial reservoir sands with over 1000ft thickness in places. Porosity ranges from 10% to 14% while permeability ranges up to 1000mD, with an average of approximately 100mD. As Sarah produces under a strong aquifer-drive, directed from the northern flanks and bottom of the field. The low mobility-ratio of oil and water phases (0.47) and generally homogeneous, thick reservoir sequences, indicate oil is swept by a favorable gravity-dominated displacement. As Sarah oil is a light crude of 38° API and formation water has total chlorides in the region of 148,000 mg/l. SCAL has been performed on a number of occasions throughout As Sarah field's life and these tests have confirmed the reservoir to be more oil than water wet. The results of oil-water relative permeability and capillary pressure measurements have given residual oil saturations ranging between 7% to 38% and irreducible water saturations in the region of 5%. The present As Sarah simulation model uses oil-water relative permeability curves calculated from porous plate capillary pressure measurements using Purcell's method. It is thought that the ultimate overall recovery factor of As Sarah field will exceed 50%.
- Africa > Middle East > Libya > Sirte District > Sirte Basin (0.99)
- Africa > Middle East > Libya > Al Wahat District > Sirte Basin > As-Sarah Field (0.99)
This reference is for an abstract only. A full paper was not submitted for this conference. Abstract This poster presents the results from a case study that integrates detailed rock mechanics and swelling tests with information from petrophysical logs and core properties acquired to evaluate, define and predict the instability mechanism in this portion of the Khafji reservoir. To achieve the objectives, 300 feet of preserved core were cut through the problematic shaly sand member using oil based mud. In addition, 200conventional plugs and 28 whole core samples from eleven wells were utilized for the purpose of developing geomechanical and pore fluid models. Both oil based mud (OBM) and water based mud (WBM) filtrate were used for the swelling and triaxial compression tests. The development of a strength and stress profile for the well is the first step in understanding wellbore instability problems. These profiles are generated using rock properties, drilling experience, in-situ stress regimes and strength measurements on core samples. The results demonstrate that the in-situ stress in the Khafji reservoir can be characterized, and the critical azimuths of marked instability increase are discernible. Wellbore instability problems can be predicted and averted. The optimum mud weight windows to drill horizontal wells have been identified using the geomechanical model. Wells oriented parallel and perpendicular to maximum horizontal stress (SHmax) require minimum mud weight of 80–84 pcf and wells drilled WNW-ESE require mud weight from 80–95 pcf.. The swelling test results point toward increased swelling in the presence of the WBM filtrate compared to the OBM filtrate and a decrease in formation compressive strength when in contact with the OBM. It may therefore be prudent to redesign the already "inhibitive" WBM to suit the formation and the clays.
- Asia > Middle East > Saudi Arabia > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Zuluf Field > Wasia Formation (0.99)
- Asia > Middle East > Saudi Arabia > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Zuluf Field > Shu′aiba Formation (0.99)
- Asia > Middle East > Saudi Arabia > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Zuluf Field > Khafji Formation (0.99)
- Asia > Middle East > Saudi Arabia > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Zuluf Field > Dair Formation (0.99)
Applications of Real-Time Downhole pH Measurements
Carnegie, Andrew John G. (Schlumberger) | Raghuraman, B. (Schlumberger) | Xian, ChengGang (Schlumberger) | Stewart, L. (Schlumberger) | Gustavson, Gale (Schlumberger) | Ruefer, Steffen (Schlumberger) | El Mahdi, Ahmed (ADCO) | Abdou, Medhat (ADCO) | Al Hosani, Amal (ADCO) | Dawoud, Ahmed (ADCO)
Abstract Real time in-situ high precision monitoring of water pH was recently performed during open hole sampling in two on-shore Abu Dhabi wells, A and B, drilled in limestone reservoirs. Sampling in well A, which was drilled with oil based mud (OBM) was to search for distinctive differences in connate water characteristics of three different reservoirs. The in-situ pH measurement interpretation agreed with those from subsequent surface analysis of (downhole) samples. The pH of one zone was identified to be significantly different from the two others. The pH values were integrated with other characteristics such as ionic and isotopic concentrations to provide a complete description of the waters. Sampling in well B, which was drilled with water based mud (WBM), was to determine the expected flow fractions of mobile formation oil and water across oil/water transition zones. The in-situ pH measurements were pivotal to this objective by providing a cost effective and reliable real time diagnostic of the level of contamination mud filtrate in formation water. Guidelines are given on how to design jobs to measure pH in-situ, and on the how to use of the data. Measurements of water characteristics, such as pH, has a wide range of applications, from determination of reservoir compartmentalization, to prediction of corrosion and scaling to improved sampling techniques. These are discussed. Introduction A method and apparatus to measure pH of water (the "pH measurement") whilst it is being pumped through the flow line of a formation tester (FT) was tested in 2 wells A and B, which were drilled in Middle East carbonate formations. Since then the same technique has been applied successfully in several more Middle East wells. The pH measurement consists of the following steps:injecting a pH sensitive colored dye into the water inside the flow line of the formation tester, ensuring that the dye reacts (and hence changes color) with the hydrogen ion in the water – when both oil and water flow a downhole separator must be used to extract the water, determining the pH by using a spectroscope to measure the intensity of colors along the wavelengths where the dye has changed color. This method is described in detail in (1). Figure 1 on page 2also illustrates the principle.
- Europe (0.69)
- North America > United States > Texas (0.46)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.24)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)