Royalty Lease Evaluation (RLE) distillation analysis was performed on six hundred (600) wells in Petrotrin's Soldado acreage. This data has been traditionally generated for use by Petrotrin's refinery to determine if the crude oil feedstock is compatible to the refinery configuration or if the crude oil could cause yield, quality and production problems. These made for refinery reports have become part of Petrotrin's legacy data. The authors decided to examine this dormant dataset to ascertain what hidden stories it may tell about the oilfields from which they came. In this investigation no data is generated, but an existing and dormant dataset will be analysed. Several components in a RLE distillation report on crude oil samples will be observed for trends, patterns and relationships. Ternary diagrams and cross-plots will be employed. Specific geochemical revelations from the RLE data will be validated by comparison to conventional gas chromatography data. This investigation will illustrate how evaporative fractionation, which is a later charge of light hydrocarbons mixing with an emplaced biodegraded oil is evidenced by a phenomenon called the" Gas Oil Anomaly", seen in the RLE data. Essentially this is the absence of any gas oil fraction combined with the presence of light hydrocarbons in the distillation data. It will also be demonstrated that presence of the later charge of light hydrocarbons has been the key factor in the prolific production from the Soldado reservoirs. Additional analysis of the light oil and gas oil fractions of a crude oil will reveal properties and characteristics that suggest there were different sources for both the originally emplaced oils and the later charge of light hydrocarbons. The data also shows that due to the evaporative fractionation phenomenon there is no correlation with API Gravity, oil viscosity, Sulphur content and depth of the reservoirs in Soldado. It will also be demonstrated that the data can be used as a qualitative tool leading to exploration plays in the Soldado acreage. Explorationists at Petrotrin will find the results of this investigation to be both useful and provocative as it directs their attention to specific Trinmar Soldado oilfields as deep exploration play areas in a manner that traditional geochemical analyses have not been able to. It also allows the practioners in the Petrotrin Soldado acreage to better understand the productivity and complex fluid distributions in the Soldado reservoirs.
In Trinidad's mature onshore oilfields, operators have traditionally forecasted the initial production rates back calculated from decline models. These rates, then reduced annually by a predetermined decline model has been used to evaluate financial feasibility. This method does not make use of the reservoir pressure. This paper demonstrates how software modelling, utilizing the reservoir pressure can reasonably forecast the performance of low rate oil producers and alert the operator of the need for artificial lift from the inception of the production cycle. The objectives of the project were to determine remaining recoverable reserves, evaluate the potential for redevelopment (workovers and infill drilling) and to demonstrate that software modeling can be used to forecast production for an oil reservoir in a mature onshore oilfield in Southern Trinidad. Petroleum Experts Integrated Production Modeling (IPM) software suite was used for building all models. A comparison of the production forecasted by software modelling and the traditional method of forecasting initial production rates by back calculating from decline models was also undertaken. Using the available data and net oilsand maps, the fault block bulk volumes, oil in place and the remaining reserves were determined. These results were then used to identify fault blocks with potential workover well candidates and infill well locations. Research of well files and well logs were used in evaluating zones for potential recompletions, reperforation or perforation of additional footage for production. Forecasting and comparison of the initial production rates and ultimate cumulative production for the proposed infill wells and recompletions using the traditional IP/Decline model method and computer modeling was then performed. Form the data available, it was determined there were four blocks with remaining reserves that could be successfully recovered. The recovery methods proposed included the workover of two existing wells and drilling of two infill wells. Initial production rates and ultimate production volumes obtained by modeling of workover and new well performance had reasonably close agreement with those obtained by the traditional IP/Decline models. The results of the modeling, however indicated that all the wells required the use of pumping mechanisms (sucker rod/beam pumps) to sustain production over a ten-year period. The need for this important production mechanism would not have been realized from the IP/Decline method. An important distinction is that the modelling makes direct use of the reservoir pressure, whereas the IP/Decline model does not.
An attempt was made to independently verify the proposed performance of the Liza 1 field using only data available in the public domain. The data used in modelling was sourced from news reports, company disclosures and the analogue Jubilee field in Ghana. Reservoir rock and fluid data from Jubilee Field was deemed an appropriate fit because of the corroboration provided by the Atlantic Drift Theory. A major challenge in creating the model, was determining the aerial extent of the field. According to Yang and Escalona (2011), the subsurface can be reasonably approximated using the surface topography which is possible via the use of GIS software. Google Earth Pro software was used to estimate the coordinates and areal extent of the Liza 1 reservoir. A scaled image of the field location showing the Guyana coastline was re-sized to fit the coastline in Google Pro and then the coordinates for the Liza field and wildcat well locations were estimated. This was used to create the isopach map and set reservoir boundaries to create the static and dynamic models in Schlumberger's Petrel E & P Software Platform (2017) and Computer Modelling Group IMEX Black Oil and Unconventional Simulator CMG IMEX (2016). The initialized model investigated the reservoir performance with and without pressure maintenance over a twenty (20) year period. The original oil in place (OOIP) estimated by the model was 7% larger than the OOIP estimated by ExxonMobil for Liza field. The model produced 35% of the OOIP compared to 50% of OOIP as forecasted by the operators. (See Table 1). The factors that strongly influenced this outcome were, the well positioning and the water injection rates. A significant percentage of the oil remained unproduced in the lower layers of the model after the 20-year period. Time did not permit further modelling to improve the performance of the model. Table 1 Comparison of The Created Model and ExxonMobil's Proposal for Liza. Property ExxonMobil's statement on Liza field Modelled field Result Original Oil in Place (MMbbl) 896 967 Oil Recovery Factor (%) 50 35 Gas production from the model would be used as gas injection from three injector wells and as fuel for the proposed 200 MW power plant for Guyana. Even so, significant volumes of natural gas remained unallocated and subsequently a valuable resource may have to be flared.
Acquisition of reservoir information from exploration campaigns in offshore oil reservoirs is a continuous challenge in today's operations. Reservoir fluid properties and reservoir parameters characterization are fundamental for the accurate reservoir description for field planning and facilities design. With the aid of new technology, data of the highest quality can be obtained while the well is being drilled. This data is a key input to the development plans for the area. For an exploration well in an offshore Trinidad and Tobago oil field, in a reservoir of mainly unconsolidated sandstones with medium oil, the main objective was to acquire early and quick identification of the oil prospect for planning appraisal wells. A wireline formation tester (WFT) dual-packer module was deployed to perform an interval pressure transient test (IPTT), also known as a mini-drillstem test (mini-DST), at the interval of interest for assessing key reservoir parameters such as vertical and horizontal permeability, damage skin, and reservoir pressure, among others, in the near-wellbore domain, in addition to fluid sampling. Downhole fluid analysis (DFA) was performed to identify the reservoir fluid properties including oil and water fraction, fluid composition, gas/oil ratio, density, viscosity, fluorescence, reflectance, and resistivity at multiple depths in real time. Also, the real-time insitu fluid characterization allowed making decisions about where and when to take the samples in an optimal amount of time. Additionally, a single-probe wireline formation tester was used to take fluid samples and to obtain a single-point formation pressure, used for determining pressure gradient. DFA was combined with pressure profiles to improve the determination of zonal connectivity across the reservoir. The combination of IPTT and real time DFA characterization was applied at multiple depths and resulted in an improved understanding of oil reservoir, as well as lessons learned about methodology and applications and recommendations for future operations.
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