a significantly shorter time.Cyclic steam injection has been performed since the early 60' s in Lake Maracaibo reservoirs.
SPE Members Abstract The development of the Orinoco extra heavy oil belt (Faja Petrolifera), known as the largest extra-heavy (8.5 API) hydrocarbon accumulation in the world, has become a major goal for the venezuelan oil industry in the next decade. The Cerro Negro area, contains 213 billion stb and the current estimation for the primary recovery factor is 12% of the stock-tank original oil in place (STOIIP). Following the exploratory campaign, in the early eighties, three pilot projects were initiated (0-16, J-20 and K-20) in the Cerro Negro Area. These pilots consist of patterns of vertical producing wells and clusters of highly deviated wells with different spacing, completion type, sand control, stimulation (huff and puff) and lifting process. Furthermore, since 1990 two horizontal wells were drilled, evaluated and monitored in cold production, using the neighboring vertical wells. The acquisition of an exceptionally large data set in the exploration/appraisal step (207 wells) and the three pilot projects (155 wells) not only provided a unique opportunity for thorough study each of the relevant disciplines involved in the reservoir management and production facilities design, but also promoted a set of new technologies to be applied in the design of the commercial development of these prolific extra heavy reservoirs. Introduction The Orinoco Belt located in south-eastern Venezuela is probably the largest essentially untapped oil accumulation in the world. North of the Orinoco River, the Belt stretches over a length of some 700 km, covering an area of approximately 54000 km 2 (greater than the size of Denmark). It contains an estimated 1182 billion bbls of original oil in place (STOIIP), distributed in three areas as follows: Cerro Negro 213 billion STB Machete-Hamaca 469 billion STB Zuata 500 billion STB The Cerro Negro area was selected as the first area to be investigated, comprising a region of 7000 km 2 and contains in the main member (Morichal formation) 157 billion bbls of STOIIP. From 1979 to 1982 a total of 207 exploratory wells were drilled and 155 wells for development including three modules 0-16, J-20 and K-20 to determine the expected performance profile for future commercial development. The K-20 modern nine-well cluster has tested 550 BOPD each well in cold production. The feasibility study of the Cerro Negro, was initiated to answer the following questions: * What effects do reservoir parameters and well design have on short and long term performance? * Which reserves are needed to support a target plateau rate of 120,000 mil stb/d and at what well spacing? * How to increase understanding of the recovery mechanisms in order to contribute to the decision making process, and to partially minimise the risk associated with the future capital expenditure required for reservoir development? According the complexity of the development of this huge heavy oil accumulations it was considered in the early 80's the necessity for starting an experimental project located in Cerro Negro (Fig. 1). This project was based on the technological background accumulated by the Venezuelan oil industry in the development of the heavy-oil reservoirs during the last thirty years. Development of Heavy-Oil Reservoirs in Venezuela Before concentrating on the Orinoco Belt a brief summary of the experience obtained in the traditional areas will be discussed as a mainframe for the paper presented. In Western Venezuela, the main Bolivar Coast reservoirs under exploitation (Bachaquero, Lagunillas and Tia Juana Post-Eocene) contain heavy crudes of 11 to 15 APT gravity, with in-situ viscosities ranging from 100 to 10,000 cp. The original oil in-place estimated for these three reservoirs is 63 billion bbl of oil. The actual recovery is 14% STOIIP mainly due to formation compaction and solution gas drive, enhanced by steam soak in most of the reservoirs. P. 207^
Brownfields are often characterized by a varying degree of maturity, both within the field and within individual reservoir units. This variation makes infill drilling more prospective in areas with fewer well penetrations and completions and less production. However, these areas are inherently more uncertain, with geological, petrophysical, and structural parameters particularly affected. A novel workflow solves the complex problem of uncertainty assessment and risk management in a brownfield redevelopment. Traditionally, a single deterministic reservoir model is built, matched, and used for predictions and infill planning. The availability of sophisticated simulation workflow tools enable the team now to explore the practical aspects of performing sophisticated reservoir description, static model construction, history matching, and forecast uncertainty analysis. Incorporated into multiple equiprobable reservoir descriptions, uncertainties are carried from the static model construction throughout the entire dynamic modeling process. History matching is conducted for all realizations, and the match quality is assessed by means of statistical analysis. The workflow facilitates generating hydrocarbon thickness maps by using the average column thickness of many simulation models instead of a dedicated single one. Target selection also accounts for possible sweep and sand risks by means of maps showing the standard deviation of the column thickness. The new framework is applied to a conceptual redevelopment of a brownfield. It increases the understanding of fluid flow processes in the reservoirs and is a vital component of the decision and risk analysis for the concept selection stage.
A novel workflow methodology that covers the entire cycle of field development maximizes the production potential and can increase reserves in stacked reservoirs. The approach will potentially reduce associated costs, risks, and uncertainties, in spite of complex geological structures and drainage patterns. The new workflow encompasses planning from concept selection to preparation of well proposals during the implementation work. Scalable to any given size of hydrocarbon prospect and number of infill wells, the computational method incorporates cross-disciplinary software (geomodeling and seismic packages) as well as reservoir, production, completion, and drilling software. Linkage between the disciplines is close and conducted iteratively, operating in parallel instead of the common sequential and decoupled approach. The method has been successfully tested in a brown field with 165 stacked reservoirs. Reserves increased significantly compared to the offset field development plan (FDP), while water production was significantly reduced. The optimized drainage pattern for the whole field also revealed significant future workover potential in shallower reservoirs, maximizing contingency and lifetime value of infill wells. Introduction Stacked reservoirs are a common occurrence among subsurface hydrocarbon accumulations. In them, each wellbore penetrates many prospective reservoirs that can range, depending on the field size and number of reservoirs, from a few into the hundreds. Technical and reservoir management considerations usually make every wellbore capable of producing from only a limited completion interval. Hence, the main objective should be to optimize not only the areal drainage pattern but also the vertical scheme. This makes the process highly complex and iterative and thus represents a complex, multidimensional optimization problem. In the current standard industry practice, the full production potential of these reservoirs is often not realized because of poor integration among individual discipline software platforms, limitations in hardware and software, and a generally too serial workflow. Trajectories are typically derived by the drilling engineer to target individual single reservoirs, disregarding the opportunities existing in the entire stack. Stacked hydrocarbon reservoirs are characterized by a varying number of reservoirs with different properties and characteristics, includingAreal and vertical extent of the individual reservoirsHydrocarbon type and propertiesReservoir quality and drive mechanismOptimum production and reservoir management strategyOptimum well type (vertical, horizontal, multilateral) and completion requirements Fig. 1 illustrates the nature of such hydrocarbon accumulation by means of an offshore oil field, which spans vertically about 5,500 ft with more than 165 individual reservoirs. Existing wellbore trajectories are shown as lines; oil-bearing zones are green; gas-bearing zones, red; and parts of the encroaching aquifer and the connate water, blue.
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