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^
The discovery of the El Furrial field in 1986 opened a new era of exploration and development in the eastern Venezuela deep basin. Current production from the field and two adjacent fields, Carito and Santa Barbara, is near 900,000 stb/D (stock tank barrels per day). Reservoir simulation has been used consistently since 1989 for reservoir management. Water injection, initiated in 1993, was identified in 1991 as a necessary process to maintain reservoir pressure above a critical asphalt flocculation pressure. Reservoir pressure below the flocculation pressure (6500 psi for 2% asphaltene content up to 8500 psi for 12%) results in significant and irreversible well productivity decline. A previously unrecognized variable in the production mechanism, necessary for the history match of observed reservoir pressure after initiation of water injection, was identified with reservoir simulation modeling. Investigation of fluid compressibility, aquifer support, and rock compressibility, identified that this variable was more important than previously assumed. The method of analysis shows that standard Teeuw 1 rock compressibility analysis is not appropriate. The method proposed by Anderson2 does. This paper focuses on the rock compressibility issue, the analysis of the data, and the method to include the results in reservoir simulation. Introduction The El Furrial field is located in Monagas State, Venezuela, approximately 20 km. west of Maturin as shown in Fig. 1. It is associated with other fields along a trend of deep thrust structures. Other fields associated with the same trend are the Orocual and Boqueron fields to the east and north, and the Carito Complex and Santa Barbara field to the west. The field is approximately 13 km. along strike and 7 km wide. The field produces from two reservoirs identified as the Naricual and Los Jabillos Formations. The gross thickness of the two reservoirs is more than 1600 feet. El Furrial field is characterized as a giant field with original-oil-in-place (OOIP) in the Naricual formation estimated to be more than 6,000 billion stb. The field was discovered in 1986 with the exploratory well FUL-1. This well was drilled through the top of the Naricual Formation, discovering medium gravity oil with an API gravity of 16° to 28° and a highly under-saturated GOR from 500 to 800 scf/stb. The initial reservoir pressure of 11020 psi, corrected to datum at 13000 feet sub sea (measured depth of approximately 13500 feet) indicated significant over-pressured conditions. Pressure data taken after water injection was started showed anomalous pressure response as predicted by material balance analysis and simulation. Figs. 2 and 3 show the original prediction of reservoir pressure for the Naricual Superior and Inferior units. Highlighted in these graphs is the departure from the observations of the simulated decline after water injection was started. The effect is more pronounced in Figure 3 in Naricual Inferior. It was determined that initial depletion of the reservoir was affected by high values of rock compressibility because of the original over-pressured reservoir condition. Naricual formation whole core was tested for rock compressibility. These data were analyzed and results show that especially at early time of production and development, where net effective overburden stress is low, the rock compressibility is non-linear and high (> 10*10 -6 psi/psi). The use and incorporation of this data in reservoir simulation is important in the history match and has a direct effect on the material balance and fluid-in-place evaluation. Rock compressibility, previously assumed to be constant (˜3*10-6 psi/psi) through the total range of reservoir pressure, shows a high initial non-linear compressibility with linear compressibility occurring after a certain net overburden stress is reach (˜4000–5000 psi). Understanding the importance of this factor in the depletion mechanism of the field is critical to reservoir management.
and 157From 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 c~uster has tested 550 BOPD each well in cold production. The feasibility study of the Cerro Negro, was initiated to answer the following questions:
Summary The El Furrial field is one of Venezuela's major field assets and is operated by PDVSA (Petroleos de Venezuela, S.A.), the national oil company. Its current production of more than 450,000 BOPD makes it a giant oil field. Development of the field, which has an average reservoir depth of approximately 15,000 ft, is in its mature stages owing to implementation of high-pressure gas injection. PDVSA has consistently followed a forward planning approach related to reservoir management. Using high-angle deviation drilling techniques allows development wells to be strategically located by penetrating the reservoir at high angles to optimize production rate, extend well life, increase reserves per well, reduce operating expenses, and reduce total field development costs. A reservoir model was constructed and simulated with detailed reservoir stratigraphy to determine realistic potential of high-angle wells (HAW's). Five wells had been drilled as of June 2000, and the first four wells have proved the effectiveness of the design. The philosophy, modeling technique, well design considerations, problems encountered, well results, and economic criteria provide a clear understanding of the risk of this technology not previously used at this depth in Venezuela. The result was the first HAW in the deep, challenging environment of eastern Venezuela. Results show that optimization objectives can be attained with HAW's, mainly increasing per-well production rate, maximizing per-well recovery, and extending the breakthrough time of gas or water from pressure maintenance and enhanced oil recovery projects. Well results indicate that the geological and simulation modeling technique is reliable and accurate. A pilot program shows that HAW technology provides major advantages to increase production rate and reduce the overall number of wells needed to reach production objectives. However, the project also has experienced a number of unexpected drilling problems.1 The costs associated with the total project are significant, but more importantly, this program becomes very attractive because of the long-term benefits of decreased water-cut related to current water injection; decreased gas breakthrough owing to high-pressure gas injection, and fewer wells required to meet production goals. Technical contributions include the following:The modeling technique of applying detailed stratigraphy to a full-scale reservoir model is accurate if performed with the appropriate objectives in mind.The application of state-of-the-art drilling techniques to attain high angles at deep drilling depth is possible; however, drilling problems caused by formation instability require more study and experience.This method can be applied to other fields in the eastern Venezuelan basin currently under, or planned to be under, enhanced recovery programs and development programs. Introduction The El Furrial field is one of several giant fields found northwest of Maturin, Venezuela, in what is described as the El Furrial thrust trend (location shown in Fig. 1). The field was discovered in 1986 with the FUL-1 well, which established production from the Naricual formation. A late 1996 study, using a full-field simulation model of the El Furrial field, showed that problems associated with gas or water breakthrough in producing wells from high-pressure gas injection and water injection can be reduced with this technology. The potential to reduce problems comes from drilling infill wells at a high angle between the advancing gas and water fronts. High-pressure gas injection was started in 1998 and was justified, in part, by this work and other associated studies. The field produces from two formations, the Naricual and Los Jabillos, giving a total gross thickness of more than 1,500 ft. The primary 1,200-ft-thick Naricual formation is divided into three major stratigraphic sequences - the Superior (upper), Medio (middle), and Inferior (lower). Net-to-gross ratio is typically 80%. Philosophy PDVSA has consistently maintained reservoir models through the years to aid in reservoir management.2 To date, eight full-field and numerous sector-simulation models have been built. Optimization of the field began in 1996. During the study, it was noted that predictions of conventional vertical infill wells drilled into the structure had short production lives because of water or gas breakthrough. The review identified the possibility of placing well trajectories between the advancing water and gas fronts. One benefit was that the production rate from new wells could be increased; this indicated that the number of development wells could be reduced, saving investment costs. Thus, the following objectives were determined.Define optimization alternatives of the El Furrial field well-development scheme. The use of nonconventional well completions such as vertical large interval single completions (LISC) and high-angle completion (HAC) wells may present a higher potential for meeting production needs at a lower total development cost.Define the most reasonable completion configuration for new wells in El Furrial field. It is probable that the entire Naricual acts as a single reservoir unit, with at least partial vertical communication existing in the majority of the field caused by fault juxtaposition and limited fractures associated with faults. Therefore, single completions in all of Naricual Superior and Medio, or Naricual Medio and Inferior, may present viable completion alternatives.Provide technical support to the Venezuelan Ministry of Mines and Energy, which approves operation philosophy, development, and completion practices. The HAW program was different from the previous accepted philosophy, so technical support was necessary to permit the FUL-63 pilot test well. High-Angle Wells This work was split into two parts. The first was an evaluation of HAC wells as an alternative to current vertical-well strategies. This includes the possible alternative of LISC completions for all of Naricual Superior and Medio. The second was additional simulation cases to test the potential development plan with only HAC wells in a full-scale reservoir model.
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