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Collaborating Authors
Abstract High-pressure steady-state flow tests on gas condensates are needed to determine relative permeabilities and their dependence on capillary number. Such experiments require large quantities of reservoir fluids. Other laboratory challenges using reservoir fluids include H2S content and high temperatures. This paper presents a method that has been used successfully to create synthetic hydrocarbon mixtures that closely mimic reservoir fluid PVT, viscosity and IFT behavior at relevant reservoir pressures. The synthetic mixtures typically consist of 3-4 hydrocarbon compounds, and are readily created in the laboratory in large quantities. The selection of a synthetic mixture starts with a known description of reservoir fluid PVT properties, from laboratory measurements and/or EOS modeling. Typical PVT include constant composition and constant volume depletion data, viscosities, and gas-oil interfacial tensions (IFT). The procedure for creating an appropriate synthetic fluid that mimics the reservoir fluid PVT behavior is selection of 3-4 available hydrocarbon compounds, always consisting of methane, at least one light intermediate (C2 to C10), and at least one heavy compound (most often Diphenylmethane DPH-C1). An automated selection process has been developed. We used the SRK EOS with zero BIPs (binary interaction parameters) to describe phase and volumetric behavior of the synthetic fluid system. With a given group of selected compounds, the amount of each compound is determined by regression to minimize the mismatch between synthetic fluid PVT and reservoir fluid PVT. The synthetic mixture component slate that gives the best match is then chosen from the many possible combinations. This method has been used for some twenty reservoir gas condensates during the past 15 years. In this paper we illustrate the method for some twelve "public" reservoir gas condensates ranging from lean- to rich fluids, with some containing significant H2S and CO2 content. The accuracy of synthetic fluid mixtures to mimic actual reservoir gas condensate behavior is surprisingly good. Laboratory applications of the methods presented in this paper have been made without experimental difficulties. In general, the modeled synthetic fluid PVT behavior predicted by an EOS are quite close to the measured laboratory PVT of the synthetic fluids. The paper provides, for the first time, documentation that 3-4 component synthetic mixtures can be used to represent reservoir gas condensate fluids covering a wide range of composition and PVT behavior.
- Asia (0.68)
- North America > Canada > Alberta (0.47)
- North America > United States (0.46)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Caroline Field > Cardium Formation (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > North Field > Laffan Formation (0.99)
- Asia > Indonesia > Sumatra > Aceh > North Sumatra Basin > B Block > Arun Field (0.99)
- Asia > Middle East > Qatar > Block 4 > Khuff Field > Khuff Formation (0.89)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
This study focuses on recent experience in Saudi Arabia with crude-oil compositional analyses during pumpout with a wireline formation tester (WFT). It summarizes experience with the in-situ measurement of methane, ethane, propane, saturates, aromatics, and gas/oil ratio (GOR) on the basis of multivariate optical computing (MOC) conducted at more than 200 pumpout stations in a total of 37 wells drilled with a variety of inclinations, bit sizes, and drilling fluids in several oil and gas fields. In reservoir-fluid characterization performed in the laboratory conventionally, samples of representative formation fluids are analyzed to determine bulk fluid properties, fluid-phase behavior, and chemical properties. Exploration and evaluation wells are often drilled exclusively for fluid-analysis purposes for which the only way to analyze or capture formation fluids is a downhole pumpout WFT (PWFT). Capturing high-quality reservoir samples is one of the most important objectives in any PWFT job.
Development and First Application of an Ultra-Low Density Non-Aqueous Reservoir Drilling Fluid in the United Arab Emirates: A Viable Technical Solution to Drill Maximum Reservoir Contact Wells Across Depleted Reservoirs
Jeughale, Ramanujan (ADNOC offshore) | Andrews, Kerron (ADNOC offshore) | Al Ali, Salim Abdalla (ADNOC offshore) | Toki, Takahiro (ADNOC offshore) | Tanaka, Hisaya (ADNOC offshore) | Sato, Ryosuke (ADNOC offshore) | Luzardo, Juan (Petrochem Ltd) | Sarap, Girish (Petrochem Ltd) | Chatterjee, Saumit (Petrochem Ltd) | Meki, Zakaria (Petrochem Ltd)
Abstract Drilling and completion operations in depleted reservoirs, are challenging due to narrow margin between pore and fracture pressures. Therefore, Ultra-Low Density Reservoir Drilling Fluid (RDF) with optimum parameters is required to drill these wells safely. Design and effective field application of a sound engineered fluid solution to fulfill these operational demands are described. Ultra-Low Density RDF NAF with minimal fluid invasion characteristics was developed after extensive lab testing, to cover the fluid density from 7.2 โ 8.0 ppg. The fluid properties were optimized based on reservoir requirements and challenging bottom-hole conditions. The design criteria benchmarks and field application details are presented. Fluids were stress tested for drill solids, reservoir water and density increase contamination. Multi-segment collaboration and teamwork were key during job planning and on-site job execution, to achieve operational success. For the first time in UAE, a major Offshore Operator successfully applied an Ultra-Low Density RDF-NAF, which provided remarkable stability and performance. The fluid was tested in the lab with polymeric viscosifier alone and in combination with organophilic clay. In order to gain rheology during the initial mixing, about 3.0 ppb of organophilic clay were introduced to system along with the polymeric viscosifier. Later, all the new fluid batches were built with polymeric additives alone to achieve target properties. A total of 10,250 ft of 8 ยฝ" horizontal section was drilled to section TD with record ROP compared to previous wells in the same field, with no fluids related complications. With limited support from the solid control equipment, the team managed to keep the density ranging from 7.5 ppg to 7.8 ppg at surface condition, using premixed dilution. Bridging was monitored through actual testing on location and successfully maintained the target PSD values throughout the section by splitting the flow on three shaker screen size combination. Due to non-operation related issues, hole was kept static for 20 days. After such long static time, 8 ยฝ" drilling BHA was run to bottom smoothly precautionary breaking circulation every 5 stands. Finally, after successful logging operation, 6 5/8" LEL liner was set to TD and the well completed as planned. Success of this field application indicates that an Ultra-Low density fluid can be designed, run successfully and deliver exemplary performance. Lessons learned are compared with conceptual design for future optimization. Laboratory test results are presented, which formed the basis of a seamless planned field application.
- North America > United States (0.68)
- Asia > Middle East > UAE > Abu Dhabi Emirate (0.29)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Zakum Concession > Zakum Field > Thamama Group Formation (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.91)
A combination of divalent base brine and high wellbore temperature presents significant challenges for high-density aqueous reservoir drilling fluids. Such systems traditionally use biopolymers as viscosifiers; however, they are subject to degradation at elevated temperatures. Nonaqueous drilling fluids are thermally stable, but complete removal of the filter cake is challenging, which can lead to formation damage. The complete paper describes the qualification and first deepwater drilling application of an aqueous reservoir drilling fluid at temperatures greater than 320 F. The laboratory development and scale-up yard trials of the high-temperature divalent brine-based reservoir drilling fluid (HT-RDF) and solids-free screen running fluid (SF-SRF) systems used for this well took several years.
Fluid Identification Challenges in the Near Critical Fluids: Case Studies in Malaysia
Kyi, Ko Ko (Petronas Carigali Sdn Bhd) | Bt Yahaya, Norfadilah (Petronas Carigali Sdn Bhd) | Daungkaew, Saifon (Schlumberger) | Hademi, Noor Rohaellizza (Schlumberger) | Cheong, Boon Cheng (Schlumberger) | Azam, Mohd Nor Hisham Mohd (Schlumberger) | Yusuf, Nora (Schlumberger) | Sinnappu, Suresh (Schlumberger) | Anh, Do Quoc (PCPPOC) | Wong, Surianee Bt Rosli (PCPP Operating Co. Sdn. Bhd.) | Nguyen Hai, Minh (PCPP)
Abstract Reservoir fluid identification plays a crucial role in reservoir characterization and hydrocarbon volume estimation. Gas condensate reservoir is well known for its complex behaviour due to the nature of a near critical fluid. The reservoir pressure and temperature in such reservoirs are very close to the critical point, and therefore, small changes in reservoir condition will result in a change of fluid properties considerably. As a result, there exists a broad spectrum of reservoir fluids in this reservoir condition. Identifying reservoir fluid in the zones of interest is extremely challenging, especially when it is associated with overpressured low porosity shaly sandstone reservoir. It becomes difficult and at times impossible to definitively identify different types of formation fluids from the well logs alone. This paper presents challenges of fluid identification process during the exploration/appraisal campaign in such reservoirs, offshore Malaysia, where the operator needs to gather as much information and as quickly as possible to make immediate operation decisions and Field Development Plans (FDP). First part of this paper demonstrates an integration of available data including mud logs, gas chromatography, gas wetness ratio, well logs, formation pressure and DST in order to determine fluid types in a well where an expected reservoir fluid is oil. The result from a systematic integrated reservoir characterization performed later, however, has found that the reservoir fluid is gas condensate. The second part shows an extensive application of Downhole Fluid Analyzer (DFA) in the Wireline Formation Tester (WFT) tool to conclusively identify reservoir fluid types and their properties in-situ and in real time in the second well drilled in a different fault block. In this case, the use of WFT together with DFA has allowed identification and PVT property determination of a full range of downhole fluids including gas, retrograde gas, volatile oil and black oil. This suggests a number of compartments in such complex reservoirs. Introduction Reservoir fluid identification plays a crucial role in reservoir characterization and hydrocarbon volume estimation. In thick, porous and clean reservoirs, the process of fluid identification is straight forward. Initially, the bulk density and neutron porosity logs are used in combination with resistivity logs to identify reservoir fluid type. In clean reservoir, density porosity log will overlay neutron porosity log in water zone. In hydrocarbon bearing zone, density and neutron porosity logs will start crossing over each other. A very large density and neutron porosity log crossover together with high value of resistivity suggests that the formation is gas bearing. Normally, formation pressure gradients obtained from wireline formation tester (WFT) tools greatly help in identifying fluid types.
- Asia > Malaysia (0.70)
- North America > United States > Texas (0.29)
- Europe > Norway > Norwegian Sea (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.69)
- Geology > Geological Subdiscipline (0.67)