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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.
Phase behavior calculations require that all components and their properties be specified. Crude oils, however, typically have hundreds of components, making the equation of state (EOS) procedure for the phase behavior of mixtures computationally intensive. Thus, components are often lumped into pseudocomponents to approximate the in-situ fluid characterization. The selection of pseudocomponents and their property values are likely not unique, as is often the case when numerous model parameters are estimated by fitting measured data with nonlinear regression. Care should be taken to avoid estimates in the pseudocomponent properties that are unphysical and to reduce the number of parameters.
Aydelotte, Robert (ExxonMobil) | Alboudwarej, Hussein (Chevron) | Dindoruk, Birol (Shell) | Qi, Yunying (Shell) | McCreless, Jacob (Schlumberger) | Nighswander, John (Schlumberger) | Kunt, Tekin Ali (Weatherford) | Lucas-Clements, Daniel (Schlumberger) | Ormerod, Laurence (Energistics) | Hollingsworth, Jay (Energistics) | Mao, Mark (Energistics)
Abstract Data associated with reservoir fluids are diverse, detailed and important. Reliable reservoir fluid properties obtained during the field's lifecycle are critical factors in planning reservoir, facilities, and well developments to maximize return on capital. Fluids data, however, are often based on samples, which are normally collected, analyzed and modelled early in the reservoir's lifecycle. Because of the diversity and physical nature of reservoir fluids, the data are usually characterized by complex experiments that represent a best approximation of fluid behavior along the entire production pathway. The quality of the results of these experiments depends on the test sample's handling and preparation, the experimental process used, and the test conditions employed. Understanding and accurately communicating this background context for fluid properties is essential to ensure that adequately representative properties are available for a specific technical workflow. This paper describes an Energistics-sponsored and proposed PRODML industry standard to consistently capture and communicate fluid and pressure-volume-temperature (PVT) analysis data covering sample acquisition, laboratory analysis, fluid system characterization, and property generation for upstream technical workflows. While not dealing with how to perform these steps in the reservoir fluid's lifecycle, this XML standard allows data to be initially incomplete and updated as additional data are developed. Also, the final products, such as a fluid property table or an equation-of-state (EOS) model, remain connected to the earlier lifecycle stages of characterization, analysis, and acquisition as well as the reports and documents created at each stage. This proposed standard is designed to improve reliability and reduce costs for data exchanges between field personnel, laboratory personnel, subject matter experts, and end users. The standard is also designed to support the evolution of a single “document” for a fluid sample's lifecycle. Other capabilities include storing these data in a system of record.
Abstract The Gimboa Field, which came on stream from April 2009, has produced different reservoir fluids compared with the fluid initialization model developed before production. The early exploration well only discovered highly biodegraded heavy oils (low API) in the field. Although some normal black oils (high API) were initialized in some reservoir segments based on the fluid samples taken during drilling of injection wells, the existence of large amount of non-biodegraded black oil had been underestimated before starting of production. The EOS fluid characterization was developed with good accuracy for limited initial reservoir fluid samples. All the initial reservoir fluid samples were taken from the same geological region. This made it difficult to have a reliable estimation of fluid distributions in other reservoir regions. Different ways to initialize the reservoir fluids have significant impacts for estimation of reservoir fluid in place, the expected drawdown pressure between the water injection wells and the producing wells, water injection speed and volume, the required gas handling capacity and finally the recovery factor. Drilling of water injectors and producers provided an opportunity to collect more reservoir fluid samples from other parts of the reservoir. Integration of available PVT, pressure gradients, and geochemistry data from the Gimboa Field provided an updated estimation of the reservoir fluids in different reservoirs. An API tracking black oil model has been selected to describe lateral fluid variation. Uncertainty is discussed as a lesson learned from this field for the later design of sampling programs for similar fields. This paper provides an insight into the importance of fluid initialization for compositional varied reservoirs. Integration of multidiscipline data is an efficient way to reduce uncertainty in fluid initialization. Introduction Block 4 is located at the southern margin of the lower Congo Basin in Angola. Fig. 1 shows the location of the Block 4. The Gimboa Field is about 85 km offshore and located in deepwater. The field was discovered in 2004 and it is the major accumulation discovered to date in Block 4. Gimboa first oil was in April 2009. More detailed field information can be found in the OTC paper by Carvalho et al. in 2009. This paper will focus on PVT and fluid issues in the Gimboa Field. The reservoirs consist of unconsolidated sands of Upper Miocene age. Three different reservoir intervals were encountered in the discovery well (Splay, Main Channel Complex and Basal Channel). The Main Channel Complex and the Basal Channel are overlying and in direct communication. These two channel systems constitute parts of the same reservoir unit. The combination of these two systems is labeled as the Lower Reservoir. The Splay system has a separate fluid and pressure system and is termed the Upper Reservoir. Fig. 2 shows both the Upper Reservoir and Lower Reservoir, together with the well locations. The discovery well was well 4–41-1 in 2004, which penetrated both reservoirs. Eight MDT reservoir fluid samples were collected from the well. The EOS fluid characterization work conducted in 2005 was based on the fluid samples only from the discovery well. Starting from 2007, more reservoir fluid samples have been taken from drilling of injection and production wells (WIU-02 and PL02).
Mississippi Canyon 348 (Camden Hills) is a recently discovered biogenic gas field in the deep-water (7200 ft) Gulf of Mexico. The gas in this field is stratigraphically and structurally trapped in a multi-story, distal turbidite channel sand complex. Although considerable work is published on biogenic gas that has been generated and trapped in shelf and deltaic depositional systems, little is understood about biogenic gas accumulations in distal, deep-water, low net sand depositional settings such as this. Given the water depth, a number of economic concerns regarding the reservoir arose during evaluation of the development and delineation wells. First, there was concern about the possible presence of wax and condensate in the reservoir gas. Detailed monitoring of the synthetic drilling mud used in the wells in conjunction with rigorous gas chromatographic analysis of the drilling mud and reservoir hydrocarbons revealed that both condensate and wax are associated with the biogenic gas.
Another engineering and economic concern in this low net sand system was the possibility of reservoir compartment-alization. Geochemical analyses of the methane revealed it to be very uniform and homogenous with respect to both its' composition and carbon isotopic signature over a vertical interval of at least 4000 ft. However, differences in isotopic signature of immature, indigenous thermogenic gases in discovery well MDT tests demonstrated vertical compart-mentalization of the various sands. Later, in the delineation well, similar gas analyses showed the main reservoir sand to be in fluid communication laterally. Early recognition of compartmentalization and the presence of wax and condensate in the reservoirs enabled Marathon to factor these considerations into the field development economics.
Camden Hills is a biogenic gas accumulation in Mississippi Canyon 348 (Fig. 1). This field, which is in 7200 ft of water, was discovered in August of 1999. The feature drilled in the discovery well was a seismic amplitude anomaly. The trap at Camden Hills is a combination stratigraphic/structural trap although the stratigraphic portion of the trap is by far dominant over the structural component (Fig. 2). Any structural relief is due to differential compaction of the distal upper middle to middle Miocene turbidite deposits (shelf equivalent biostratigraphic zone is the Textularia W) that form both the reservoir and most of the seals at Camden Hills. Specifically, the reservoir at Camden Hills is a series of multi-story, distal turbidite channel sands. Based on core measurements taken in the major reservoir interval (Text. W-D), porosity in these sands ranges from 25 to 30% and averages 29%. Similarly, core permeability measurements indicate permeability varying between 200 to 4700 md with an average around 1500 to 2000 md. The reservoir temperature at Camden Hills is 155 degrees Fahrenheit, and reservoir pressure is 7400 pounds per square inch.
Deepwater Biogenic Gas
Examples of biogenic gas accumulations in shallow water, deltaic deposits are fairly well known. However, biogenic gas fields in deep-water, distal, low net sand systems such as the one at Camden Hills are not well documented. Prior to considering the Camden Hills biogenic gas accumulation in detail, it is first helpful to review some general concepts governing biogenic gas generation, migration and trapping. Some of the conditions favorable to biogenic gas generation are: 1) anoxic environment, 2) low sulfate environment, 3) low temperature (less than about 97 degrees Celsius), 4) adequate total organic carbon content, 5) sufficient pore space and 6) favorable rates of sediment deposition1,2.