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Abstract This paper presents the results from Modern Decline Analysis and Material Balance study in a mature Field, in the Sabah State of the region of Malaysia. The study represents the first part of ongoing subsurface evaluations. The identification of non-drained areas using Modern Decline Analysis together with the use of Material Balance has led successfully not only to evaluate the potential but also to successfully determining the viability of infill well locations. Prior to obtaining a clear understanding of the subsurface drive mechanisms and production data, reservoir simulation was used to establish reservoir potential and carry out infill drilling evaluations. The results were highly variable and optimistic in some cases, and somewhat disappointing in others. Subsequent well results indicated large discrepancies between the static models and the actual field results. Once these discrepancies had been reconciled, a consistent understanding of the reservoir performance began to develop. This paper presents the results of applying modern decline analysis and material balance techniques to different reservoirs, starting from the basic steps of quality assurance and quality review of the entire production data, in order to incorporate them together with the pressure of the neighbouring wells to the future infill target. Each reservoir was matched to the observed pressure, for both techniques Modern Decline Analysis and Material Balance, which again showed signs of nondrained areas, secondary support mechanism and infill opportunities. Modern Decline Analysis was carried out for each of the wells and from the results, a map of Contacted oil Volumes and Recovery Factor was generated for each of the reservoirs, where zones of high oil contacted volumes and low recovery factors were identified. Later Material Balance was applied to assess on the energy levels of the non-drained areas. As a result, several optimization and infill opportunities were identified.
Abstract This paper builds on the results of previous work related to determining the drive mechanisms of the Mene Grande field. Various studies have been performed recently which all have indicated that the dominant water production mechanisms is depletion of the reservoir mustones or shales. This revelation has allowed both old and new data to be viewed in a new context which has led to a greater understanding of the reservoir bahviour. Both the long term, data and recent transient analysis strongly indicate the presence of dynamic system behaving as two separate systems. These two systems can roughly be classified as oil filled sandstone, and water filled mudstone. The permeability and volumetric differences are sufficient to induce a typical layered reservoir response. The field data and supporting studies for this drive mechanism have been reported previously. In this paper we describe the reservoir simulation methodology adopted in order to best represent this heterogeneus system. A dual permeability model has been used with the mudstone acting as the "matrix" and the sandstone as the "fracture". The matrix-fracture transfer function acts as a very efficient history match parameter both for pressure and water cut. The results of both conceptual and well by well history matches are presented confirming that the methodology is well suited for modeling such systems. The quality of the water cut match even during the early stages of the work is quite remarkable. This paper will be focused mainly toward the dynamic model, since the geological model was explained in a previous work (See reference 1 for further details). Introduction The Mene Grande Field is located in the occident of Venezuela. Its extension is 123 km, and has 880 wells drilled so far. The field is situated approximately 120 km southeast of Maracaibo city, in the Zulia state. Mene Grande was the first oil field discovered in Venezuela in 1914, with the drilling of the Zumaque-1 in 1914, which still is on production. Repsol-YPF started their operations in this field in 1998, as a part of the 3rd licensing round in Venezuela. The Mene Grande field, is a fluvial reservoir which comprises the Isnotu formation, of age Miocene. The Isnotu formation is bounded above and below by unconformities. This formation is a combination of three main levels, the "K" sands, the "KLM" clays and the "LM" sands. Since the "LM" sands are the main producer sands. The simulation model was focused on defining new infill localizations within this horizon. The "LM" sands, comprises unconsolidated fluvial channel sands and crevasse splays. The initial model was black oil, where, in spite of a series of efforts to obtain a history match, it was not possible to reproduce the strong fall of initial pressure and the maintenance of the stable pressure trend, and on the other hand reproduce the observed water cuts for the field. It was, after analyzing a series of previous studies (ref. 1), that the initial model was modified to one of double permeability. Where the matrix-fracture transfer function plays an important part in obtaining an acceptable history match. Dual Porosity Models - Basic Theory The dual porosity single permeability or dual porosity dual permeability models have often been used to describe naturally fractured reservoirs. In dual porosity reservoirs the fluids exist in two systems:The rock matrix, which usually provides the bulk of the reservoir volume. The highly permeable fracture system.
Abstract The Mene Grande field has been producing since the early 1900s. Water production has been observed since the beginning with a slow steady increase in field water cut, which is currently at 40%. The watercut is repeatedly observed to decrease with increasing oil production and increase with decreasing oil production. This phenomenon can be repeated within a single well multiple times. Another typical production behavior of the Mene Grande Field is a double decline in production rate when plotted on semi-log paper much like a two layer system. The current study seeks to offer an explanation for this unusual reservoir behavior with a focus on integrating production data, and quality control of the geostatistical model using pressure transient analysis, material balance and variogram analysis. Detailed well models have been used to guide the geostatistical input by history matching selected transient tests including the very characteristic derivative response of this heterogeneous fluvial reservoir. Additional quality control has been obtained by matching variograms from pseudo wells in the inter-well area. These variograms have both highlighted flaws and suggested remedies to the previous modeling methodology. The overwhelming conclusion is that the dominant source of water production is the depletion of the reservoir shale. This conclusion also provides significant insight into the reservoir characterization and communication levels within the field. The results have had a direct impact on completion strategies and IOR evaluations. The results of this work demonstrate how the use and combination of traditional analysis can be integrated to enhance the reservoir characterization process. The methodology applied during this work can easily be included in similar reservoir characterization projects. To our knowledge significant water production and pressure support has not previously been linked to the depletion of reservoir shales within oil reservoirs. It is however felt that this mechanism offers an explanation for many of the Costal Bolivar fields, which tend to have similar water production profiles over the long term. Introduction Mene Grande was the very first oil field discovered in Venezuela in 1914, with the drilling of the Zumaque-1 (the discovery well), which is still producing 20 bopd. The Field is situated approximately 120 km southeast of Maracaibo City on the eastern side of the Lake Maracaibo Basin. The field extension is 123 km2 and 917 wells have been drilled to date since the field was discovered. How many active?? The field comprises a heavy oil Miocene reservoir with overlying stratified tar sands within the 1200–1500ft thick Isnotu Formation. The Isnotu Formation is bounded above and below by unconformities. The Isnotu Formation lies unconformably upon sands and muds of the Eocene Pauji Formation. The reservoir comprises unconsolidated fluvial channel sands and crevasse splays, bounded by poorly indurated muds and silts. The overall net sand/gross percentage in the total reservoir is generally low to moderate varying between 10 and 35%. The oil found in the Miocene formation has an API varying between 12 and 20 and has a viscosity between 10–30 cp. Most wells are producing under artificial lift conditions (Rod Pump and PCP).
Abstract Numerical simulation of reservoirs is one of the most important engineering tools in monitoring mature fields, but depending on the precision and heterogeneity of the data, it can be replaced with an analysis based on statistics and production management. Señal Picada field, located in The Naquin Province, Argentina, was discovered in 1963. It produced by primary recovery with an almost null declination for more than 12 years. After that, a disorganized secondary recovery process started in 1976, which increased substantially the water cut, due to an early waterfront irruption. In 2002, a reservoir numerical simulator was developed just for an isolated block that contained the 30% of the total reserves of the oilfield. Due to the uncertainty generated by the quantity and quality of the historical data, the possibility of extrapolate the results of the simulator to another areas was evaluated versus other techniques. In a scenario of high oil prices, it is quite important to have no delays in implementing field development activities. Here is where the choice of one or another methodology can make an economical difference. All uncertainties involved in field development through different methodologies, such as water conformance, Pattern Injection modifications, etc., can be minimized by the analysis of production data and statistical reserves analysis, combined with an analytical simulation. This allows a plan for recovery reserves faster than the construction of a numerical simulation model. In the case of Señal Picada, due to the heterogeneity of the data, an accurate simulation of the entire reservoir would take a long time. The use of statistics and production data analysis guided by the analytical simulation has offered an accurate overview of the field behavior. Complementing this evaluation with the results of the numerical simulator, it will accelerate incremental oil production, maximizing the field internal rate of return. Introduction About 85% of Argentina's oil production comes from nearly depleted fields that depend on oil prices and advanced technology to continue producing economically. After reaching a peak in 1998, oil production has been declining progressively, however, in the last three years the decline rate has diminished due to implementing Integrated Reservoir Management in mature fields 1. Señal Picada, discovered in 1963 and located in the Neuquén Basin, Western-Central Argentina, contributes with 5600 barrels per day of oil (900m3/d) from 180 active wells. The actual total oil production is 122.6 MMBls (19.5 MM m3) for a recovery factor of 30%. In 1976, a secondary recovery waterflooding process started trying to increase oil production. Although there was some indication of pressure sustain and some compensation for production decline, there was no substantial increments in oil rates. By 1984, when injection patterns were all over the field, the oil production curve remained almost flat but water cut increased from 10 to 90% due to an early waterfront irruption. Looking for some production behavior explanation, a reservoir numerical model was built in 2002. It was developed just for an isolated block containing 30% of total field reserves. Even though the current history matching confirms the calibration of the simulator, the assumptions considered in the construction of this model were oversimplified because injection and production history data accuracy. Keeping these facts in mind a question is risen: Can this numerical model be good enough to describe and generate further and economically viable exploitation plans for adjacent areas in this reservoir?
Abstract This paper is a case study of the redevelopment of a highly complex and heterogeneous reservoir located in the folded belt of Neuquén basin, Argentina. The objective is to describe the integrated reservoir study that was performed; as a consequence, an aggressive drilling campaign was implemented which derived in a boost in production with no substantial interference among wells. The field was in a mature stage as it came into production in 1984 by primary recovery and oil rate was declining steadily. Cerro Fortunoso field represents a challenge for optimising the depletion strategy because of its non conventional qualities such as the presence of an under-saturated oil in coexistence with an extensive CO2 gas cap, the heavy oil located in a highly heterogeneous fluvial reservoir with poor petrophysical conditions and flanks dipping more than 60 degrees. Besides good data acquisition for seismic is hindered by surface volcanic rocks and complex geology. Field operation is intricate because it is placed in a natural reserve; as a result, drilling and production activities are more expensive in order to comply with environmental regulations. As the reserve to production ratio was exceptionally high compared to other fields in the area, it was suggested that production could be increased but the challenge was how to accomplish this objective in a supposedly fully developed reservoir where the low productivity of the wells had a profound impact on economics. The multidisciplinary team concluded that both the geological and engineering features contributed to a low recovery factor which could be improved by infill drilling. New technology was used to drill 9 vertical and 16 deviated wells in only two years. The results were so spectacular that it not only arrested decline but also established a new peak of production. The conclusions show that many fields that are thought to be fully developed, still have a lot of new oil to be produced. Reservoir management plays a major role by improving final recovery and project economics. Introduction: location and description of the field Cerro Fortunoso field, operated by Repsol-YPF, is located approximately 130 km south-southeast of the town of Malargüe, in the southern portion of Mendoza province. It lies on the southern segment of the Malargue fold and thrust belt, that extends north of the Payun volcanic center and east of the Paluaco Uplift - Figure 1. It occupies an intermediate position between the fold and thrust belt and the narrow foreland platform area south of Llancanelo lake, close to the eastern basin margin within this area. The topography is dominated by the Cerro Payun Matru, a large volcano that rises to 3680 m above sea level, and occurs 11 km to the southeast of the field; extensive basalt flows cover most of the surrounding field area; as a result good data acquisition for seismic interpretation is hindered by surface volcanic rocks. The field is located in an environmental protection region known as La Payunia reservation, Argentina´s largest volcanic valley on the eastern flank of the Andean Cordillera. The entire area was declared an ecological reservation by the province government. Cerro Fortunoso is a NNE oriented anticline with approximately 12 km in length and 2.5 km wide, with some 1000 m of vertical relief at the top of Neuquen level, the productive reservoir. Middle to Late Cenozoic deformation (Andean orogeny) of the Jurassic - Cretaceous section, resulted in the formation of this tightly folded anticline. Beds are steeply dipping on both flanks, with dips up to 70 degrees. The Neuquen Group is comprised by sandstones, conglomerates and clays, a syn-orogenic, non marine, red bed type deposit approximately 800 m thick - figure 2 - stratigraphic column. The reservoir units are unusual in that they consist of a large number of thin (1–3 meters) sandstones interbedded with, and enclosed by, red shales. A high percentage of them are of volcaniclastic composition. Study of nearby thrust-faulted outcrops shows that the sandstones are sharp-based and channelized with lateral extents of about 100–150 meters.