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Abstract Traditional petrophysical well evaluation, is able to show an integrated analysis where the log information is transformed into a lithology, water, oil, gas saturation curves, along a specific interval of a well. This method, is not able to predict how much the production of those intervals could be, when completed. With this new methodology the same approach is used, but magnetic resonance and pressure data, is integrated. As magnetic resonance, allows the discrimination among irreducible and moveable fluid saturation and also indicating the better permeability zones, it is used as a guide for the point selection for the modular dynamic formation tester. Based on this data set, the pressure, a skin factor is determined and the relative permeability to the reservoir fluid, is defined. In low resistivity reservoirs, were the traditional calculation could show high water saturation, the new technology will allow the engineer to discriminate if the water is going to flow or not, maximizing the reservoir potential. Having defined the lithology, pressure, permeability, fluids distribution and fluids saturation a synthetic production flow profile log, can be generated for each selected interval, allowing an optimized selection of the best possible intervals or overlooked zones, maximizing the final production of the well. In conclusion, new technology and power full computer calculation have a big impact in the well completion and production maximization of reservoirs. Introduction Petrophysical evaluation of thin laminated sand shale gas bearing sequences, was one of the most difficult tasks for the geoscientists in the industry. Using the conventional technologies the main gas indicators widely used are the Density log combined with the Neutron log, so the cross over of these two curves is interpreted as a gas zone but the water content of the clay particles which have large amounts of water, could push the neutron log response in the opposite direction and the gas presence is not seen. So neutron log is not the best gas indicator in such lithologies, therefore the use of a tool, which is less affected by the water associated to clay, could show gas zones never detected before with the conventional combination. Discussion This new option of log combination for gas detection is called DMR,where the density log is combined with the magnetic resonance log in order to identify the potential intervals independently from the shalyness of the reservoirs. The magnetic resonance log is able to detect the volumes of water associated to clays so when gas is present, it will still show a lower porosity due to this effect and a cross over of the two curves could be seen. This response is shown in figure 1. The ELAN type analysis presents an integrated answer of the Saturation calculation for water and hydrocarbon's, but it had the limitation of discrimination between movable and irreducible water, oil or gas. Incorporating the NMR data, this point is solved, as is showed in figure 2. Here not only the water saturation is shown, but the two fluid conditions, total porosity and hydrocarbon saturation is presented.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.37)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.36)
Abstract This study is based on data from Gulf-of-Mexico (three wells) and West Siberia, Russia (two wells). We find a clear correlation between the NMR signal and depositional environments that also were identified on conventional log diagrams and in cores. Key sediments associated with the regressive bar and coastal fluvial sand sequences (distributary mouth bar, distal bar, delta-front, and pro-delta facies) were defined by predominant type and distribution of porosity and recognized on NMR diagrams. Corresponding distribution of total and effective porosity, permeability and amount of capillary bound water characterized the major depositional environments. Seven rock types (lithofacies) were defined using statistical analysis of porosity/permeability laboratory data, SEM and thin-section description and mercury injection results; four of them were clearly correlated to various shapes of NMR response. The mixed type of porosity (associated with kaolinite cement) and interbeds with carbonate concretions (hardstreaks) were not recognized. The dissolution of feldspar grains in distal mouth bar facies results in significant enhancing effective porosity and permeability. An abnormally height porosity values (higher than 26 pu.) were formed as the result of feldspar and rock fragments total dissolution. Partial dissolution produces a micro-porosity that contains bound water. Results from both processes were recognized on NMR T2 distribution diagram. A dual porosity system was also identified on porosity-permeability cross-plot as two parallel areas. NMR signals characterize the spectral porosity distribution and therefore could be used for various facies differentiation. It provides a unique information on diagenetic alteration especially about total or partial grains dissolution. Best results on quantitative interpretation could be achieved by combining analysis of core data (SEM) and NMR logs. Introduction NMR measurements in reservoirs could be used for a wide range of applications. Although this technique is based on measuring porosity distributed via pore sizes, other parameters such as permeability, amount and type of movable fluids, surface-to-volume ratio also could be derived from initial signal. Recently NMR has been proposed as a unique method for pore and frcature pressure determination and early recognition of abnormally high pressured seals. We analyzed a NMR relaxation time T2 (the spin-spin decay time) distribution in various lithofacies in the regressive bar sequences, of early Miocene age, Gulf of Mexico and Lower Cretaceous age, West Siberia, Russia. More than 120 thin-sections and SEM images were evaluated and tied to spectral porosity distribution from NMR (nuclear magnetic resonance) logs in both basins. Out of seven lithofacies, associated with four major depositional environments, five had a distinct recognizable pattern of NMR data: MSIG, MBVI, MFFI and CBW. Lithofacies Description of the Regressive Bar Sequence Individual lithofacies description and depositional environment interpretation were based on three intervals of early Miocene age sands from offshore wells in Matagorda Island Field (MI622/23 blocks) and two intervals from wells in Samotlor Field. Sedimentological description indicates the cored intervals recovered as a part of coarsening-upward clastic (predominantly sands) sequence of delta front and distributary-to-distal mouth bar with possible presence of prodelta claystones at the very bottom parts. This sequence is overlapped with prodelta - delta front claystones. These conclusions are made based on core observations, and afterwards compared with literature sources and our previous interpretation. Major lithofacial units with correspondent type of predominant pore system characterize each of these depositional facies (see Table 1). Actual values are given for Gulf-of-mexico offshore study.
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.25)
- North America > United States > Utah (0.24)
- North America > United States > Gulf of Mexico > Western GOM (0.24)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.77)
- Geology > Mineral > Silicate > Tectosilicate > Feldspar (0.49)
- North America > United States > Utah > Island Field (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Samotlorskoye Field (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Sedimentology (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Stratigraphic Architecture and Sedimentology of the Main Oil-Producing Stratigraphic Interval at the Cantarell Oil Field: the K/T Boundary Sedimentary Succession
Murillo-Muneton, G. (Instituto Mexicano del Petroleo) | Grajales-Nishimura, J.M. (Instituto Mexicano del Petroleo) | Cedillo-Pardo, E. (Instituto Mexicano del Petroleo) | Garcia-Hernandez, J. (PEMEX Exploracion y Produccion) | Hernandez-Garcia, S. (PEMEX Exploracion y Produccion)
Abstract Detailed stratigraphic and sedimentologic analysis of the main oil-producing stratigraphic interval at the Cantarell Oil Field suggests a general graded stratigraphic architecture for the Cretaceous-Tertiary (K/T) boundary carbonate sedimentary succession. Extensive well log data, core description and petrographic analysis, as well as comparison with contemporaneous outcrop analogs, indicate that this interval is dominated by a thick carbonate breccia genetically related to the Chicxulub meteorite-impact event occurred in northern Yucatan. The carbonate breccia deposit is consisting with a base-of-slope apron. Introduction Two distinct types of sedimentary accumulations have been documented near or at the Cretaceous-Tertiary (K/T) boundary stratigraphy across the Gulf of Mexico region. These sedimentary deposits are interpreted to be genetically related to the Chicxulub meteorite impact event occurred in northern Yucatan at Cretaceous/Tertiary boundary time. For example, in Alabama, Texas and northeastern Mexico, the K-T boundary terrigenous sedimentary succession consists of a high-energy coarse clastic unit, as much as 4 m thick, with ejecta material at its base and a clay bed with a typical Ir anomaly at its top. On the other hand, in K/T boundary outcrops of southeastern Mexico, in the Chiapas and Tabasco region, a deep-water carbonate breccia is overlain gradationally by a horizon with abundant ejecta material. Thickness of this carbonate breccia reaches several tens of meters. Because the extensive known evidences of the K/T boundary meteorite impact event in distant geologic outcrops, it is predictable that its effect may have been recorded in offshore locations at a closer proximity to the Chicxulub crater site, including the western margin of the Yucatan Platform. For example, a K/T boundary calcareous breccia similar to that in southeastern Mexico with a remarkable thickness of 450 m or more than 300 m has been reinterpreted as an impact-related sedimentary accumulation in western Cuba. Moreover, there is evidence for platform margin collapse and debris-flow deposits at several Ocean Drilling Program sites proximal to the Chicxulub crater induced by the Chicxulub impact event. The offshore zone in the western margin of the Yucatan platform, also known as the Campeche Bank or Campeche Bay, is the current most prolific oil-producing province in southeastern Mexico (Figure 1). The Cantarell oil field, the largest oil field in Mexico, is located in offshore Campeche and has produced more than 6,934 million barrels of oil and 2,954 billion of cubic feet of gas. It contains additional recoverable reserves of 10,176 million barrels of oil and 5,169 billion of cubic feet of gas. Oil production in the Cantarell oil field, and nearby fields, is obtained from four different stratigraphic horizons including the Upper Jurassic (Oxfordian and Kimmeridgian), Lower Cretaceous and a K/T boundary carbonate breccia (Figure 2). The main oil-producing K/T boundary carbonate breccia in the Cantarell oil field is part of a sedimentary succession that contains numerous stratigraphic, sedimentologic, and mineralogic characteristics that suggest a genetic link to the Chicxulub impact event in northern Yucatan. Although this important petroliferous stratigraphic unit underwent a subsequent complex history of diagenetic processes and tectonic deformation, it is critical to know its internal stratigraphic array for exploitation and exploration aims. In order to understand better the responsible mechanisms that gave place to the stratigraphic architecture of this unique naturally fractured carbonate reservoir, we examine in this paper a broad geologic data set.
- Phanerozoic > Mesozoic > Jurassic > Upper Jurassic (0.68)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous (0.48)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous (0.47)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.46)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Northeast Marine Region > Cantarell Field (0.99)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Ku-Maloob-Zaap Field (0.99)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Ek Balam Field (0.99)
- (4 more...)
Abstract This paper contains a condensed description of recent developments in completion technology and relates how these technologies have enabled novel production methods. Field applications reveal the geological, reservoir and surface characteristics that favor the application of these methods. Introduction Developments in completion technology are a natural consequence of developments in drilling technology. Today, virtually all configurations that can be drilled can also be completed. This is due to important developments in multilateral, sand control, flow control, artificial lift, and monitoring technologies. In the domain of multilaterals, a polarization of technology around the level-3 and level-6 systems is observed. In the domain of sand control, screens, gravel-packs, and fracturing techniques exhibit notable developments. In the domain of flow control, a large spectrum of technology from discrete to continuous valves covering a wide range of flowrates is observed. In the domain of artificial lift, a number of developments related to electrical submersible pumps for deployment in gassy, sandy, and subsea settings are observed. In the domain of permanent monitoring an evolution from pressure to flow monitoring and an emergence of distributed measurements is noted. The combinability of these technologies is essential for the proliferation and further evolution of novel production methods. Completion Technology Multilaterals — Multilateral wells can be broadly divided into two groups — those that offer no hydraulic isolation between the laterals (levels 1–4) and those that do (levels 5–6). The level-3 and level-6 systems have emerged as the prime candidates for applications that require no or full hydraulic isolation between the laterals. Level-3 junctions provide a pre-milled window system with liner tieback. The mechanical junction gives full reentry access to the mainbore and the lateral. As fullbore access is available pumps can be placed below the junction and closer to the reservoir. Level-6 junctions have full pressure integrity achieved by the main casing string. A recent system is the preformed level-6 where the junction is run to the bottom of the parent casing in compressed state. A wireline-conveyed expansion tool reforms and expands the junction to provide two laterals with the same diameter. The reformed junction has high strength and provides hydraulic and pressure integrity. Sand Control — Sand control methods can be classified as chemical, mechanical, or hydraulic. Chemical methods are in-situ sand consolidation and resin injection. Mechanical methods are screens and gravel packs. Screen types now include simple and double wire-wrapped screens and slotted liners, screens pre-packed with gravel, and screens that can expand downhole to cover a larger surface area. In gravel packing, a new method combines carrier fluid and shunt tubes to provide a way for slurry to bypass gravel bridges and fill in the voids. Hydraulic methods involve fracturing. Single-trip perforating, fracturing, and packing methods have been developed.
- North America (0.49)
- Asia (0.47)
- Europe > United Kingdom (0.29)
- Europe > United Kingdom > North Sea > Central North Sea > Ness Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Ness Formation (0.99)
Abstract It is generally accepted that the success of underbalanced drilling (UBD) operations is dependent on maintaining the wellbore pressure between boundaries determined by the formation pressure, wellbore stability, and the flow capacity of the surface equipment. Therefore, the ability to accurately predict wellbore pressure is critically important for both designing the UBD operation and predicting the effect of changes in the actual operation. Most of the pressure prediction approaches used in current practice for UBD are based on empirical correlations, which frequently fail to accurately predict the wellbore pressure. Consequently, the current trend is toward increasing use of prediction methods based on phenomenological or mechanistic models. This paper presents an improved, comprehensive, mechanistic model for pressure predictions throughout a well during UBD operations. The comprehensive model is composed of a set of state-of-the-art mechanistic steady-state models for predicting flow patterns and calculating pressure and two-phase flow parameters in bubble, dispersed bubble, and slug flow. In contrast to other mechanistic methods developed for UBD operations, the present model takes into account the entire flowpath including downward two-phase flow through the drill string, two-phase flow through the bit nozzles, and upward two-phase flow through the annulus. Additionally, more rigorous, analytical modifications to the previous mechanistic models for UBD give improved wellbore pressure predictions for steady state flow conditions. The results of using the new, comprehensive model were validated against two real wellbore configurations with different flow areas. Field data from a Mexican well, drilled with the simultaneous injection of nitrogen and a non-Newtonian fluid and full-scale experimental data from the literature validate the improved model predictions. Additionally, a comparison of the model results against two commercial UBD simulators, which rely on empirical correlations, confirm the expectation that mechanistic models perform better in predicting two phase flow parameters in UBD operations. Introduction Because of the complex nature of the hydraulic system of UBD operations in which two or more phases (liquid, gas, and solids) commonly flow, the prediction of pressure drop and flow parameters such as liquid holdup and in-situ liquid and gas velocities are mainly performed using empirical two-phase flow methods. The Beggs and Brill correlation is the most popular among the current commercial UBD simulators. However, it is recognized by the petroleum industry that most of these empirical correlations were developed from large experimental databases, thereby making extrapolation hazardous . Moreover, the Beggs and Brill correlation has been shown to over predict or fail to predict bottom hole pressures for both vertical or horizontal UBD operations. Since the mid 1970's, significant progress has been made in understanding the physics of two-phase flow in pipes and production systems. This progress has resulted in several two-phase flow mechanistic models to simulate pipelines and wells under steady state as well as transient conditions. Consequently, mechanistic models, rather than empirical correlations, are being used with increasing frequency for design of multiphase production systems. Based on this trend of improvement, the application of mechanistic models to predict wellbore pressure and two-phase flow parameters seems to be the solution to increase the success of UBD operations by improving such predictions. Literature Review. Bijleveld et al developed a steady state UBD program to assist well engineers in planning and executing underbalanced operations. This in-house computer program uses the mechanistic two-phase flow approach. However, there is almost no technical information in the literature about the implementation of the mechanistic models in UBD operations.
- North America > United States > Texas (0.68)
- North America > Mexico (0.68)
- North America > United States > Montana > Darling Field (0.89)
- North America > Canada > Alberta > Gunn Field > Antares Et Al Gunn 6-16-55-3 Well (0.89)
Abstract Applications of a commercial numerical reservoir simulator to several large tight-sand compartmented gas reservoirs are illustrated. The applications include connecting well-pipelines networks with intermediate gathering and compression stations connected to gas transmission line nodes. The study was focused on a large gas fields-complex, which has 550 wells producing from 840 completions, and a surface gathering network with more that 1300 kilometers of pipelines. The applications of integrated reservoir-surface network simulation were oriented to support the field production strategy by designing long term forecasting and modification and/or allocation of additional surface facilities. The results showed that an advantage of this integrated reservoir-network modeling is that it takes into account the effect of several reservoirs sharing a surface network on the field and wells deliverability. Conventional reservoir simulation generally ignores these effects. Integrated simulation offered useful insights in planning and support of the reservoir management in developing tight gas reservoirs in the North of Mexico. Introduction Successful applications of reservoir-network simulation at large fields have been recently discussed in the literature. However, large compartmented gas field simulations have not been presented. Redevelopment of production in tight gas reservoirs of north of Mexico has mostly been based on 3-D seismic and hydraulic fracturing modern technology applications, in such a way that the simulation of the flow dynamics has played a secondary role. Numerical treatment of complexities such as active nature of faults, microfractures, hydraulic fractures, geomechanical response of tight rocks and nature of flow through compartments are just some aspects that have limited the application of reservoir simulation in tight gas reservoirs. The present paper proves that some of these difficulties can be conveniently handled and overcome. Tight-sand gas reservoirs in a north of Mexico basin comprise several isolated compartments in staircase-like configurations due to the heavy faulting and sealing of the faults. Smearing of shale and clays within the faults and juxtaposition of sand and shale strata provides the sealing mechanism. The high number of sands, compartments and faults are not usually fully described by the geological studies made prior to simulation studies and alternate methods must be used instead of the ideal geology to simulation progression. To make numerical simulations of reservoirs in that zone programs were developed to translate well petrophysical data into appropriate input files for numerical simulation. The large low permeability gas fields of the basin produce into a large complex surface gathering network. Field case A is connected to a network is 42 kilometers long and 10 kilometers wide; production is from commingled Mount Selman and Wilcox formations. These formations are initially overpressurized, and are commonly hydraulically fractured. The average production from the complex is 0.5 Bscfd, and an aggressive additional development is being implemented to sustain the current total production rate. Simulation input Reservoir structure and properties. A comprehensive geological description of the several productive compartments was not available for the field cases that were studied. Most of the sands are a few meters thick at depths below two thousand meters and only the main producing strata have been mapped with depth contours and faults. Due to the intricate structure of the compartments interpolation and extrapolation of depths or petrophysical properties becomes meaningless. The following scheme was developed to overcome such impasse.
- North America > Mexico (1.00)
- North America > United States > Texas (0.49)
- Geophysics > Seismic Surveying (0.54)
- Geophysics > Borehole Geophysics (0.47)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design (1.00)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Communications > Networks (0.82)
Abstract This paper describes a variety of Coiled Tubing perforating approaches and techniques which have been evaluated, planned and implemented during the development of the Cusiana and Cupiagua Fields. A synopsis has also been prepared which outlines the advantages/disadvantages of each of these approaches. In addition, several detailed case-histories are included which provide the actual Operating characteristics of each approach. The particular operational advantages, of Coiled Tubing Perforating, for Cusiana and Cupiagua have also been summarized. These include, the long intervals, deep wells, complex well trajectories, large gun-size, pre-frac requirements and poorly understood pore-pressures. An assessment has also been made of the additional benefits, IOR, cost savings, etc. that these techniques have potentially provided. Finally, there is some discussion as to the future direction of Coiled Tubing perforating for the Cusiana and Cupiagua Fields. Issues include a clearer definition of the Opportunities/Requirements and the additional Techniques/Systems which will be necessary to allow these to be realized. Introduction During the development of the Cusiana and Cupiagua Fields; customized charges were designed specifically for these non-homogeneous Quartz-Arenite formations. These resulted in a measurable productivity improvement, however the overall perforating efficiency remained low. As a better understanding of the mechanisms involved was acquired, it became clear that one of the primary factors affecting the perforating efficiency was the magnitude of the under-balance achieved. From the available data, it could be seen that this parameter had a considerable impact on the initial productivity or injectivity. Perforating operations utilizing electric-line are typically limited as to the absolute magnitude of under-balance at which they can safely operate. In addition tortuous, side-tracked and deep well trajectories can create excessive drag-forces, which cause operational problems and result in forces close to the operational limitations of the cable. In recent Years Coiled Tubing conveyed perforating has proven to be an excellent alternative to electric-line; in terms of achieving substantially higher values of underbalance and when attempting to access deep and highly deviated wells where dog leg severity may be a concern. Background Two major oil fields under development in the Casanare Region of Colombia are the Cusiana and Cupiagua Fields. The Cusiana and Cupiagua Fields are located in the foothills on the Eastern side of the Eastern Cordillera of the Andes mountain range. The current tectonic environment is characterized by active thrust faulting towards the South-East, the direction of maximum horizontal stress. Reservoir bed dipping can be severe, this generally results in the wells following a natural walk, while being drilled, towards the preferred azimuth of fracture propagation.
- South America > Colombia > Casanare Department (1.00)
- North America > United States > Texas > Dallas County (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.88)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.54)
- South America > Colombia > Mirador Formation (0.99)
- South America > Colombia > Guadalupe Formation (0.99)
- South America > Colombia > Casanare Department > Llanos Basin > Cusiana Field > Mirador Formation (0.93)
- (3 more...)
Abstract The Lagunillas 07 reservoir is located on the eastern part of Lake Maracaibo in Venezuela. The reservoir contains the Laguna formation, the Lagunillas formation and the La Rosa formation. The sands are of the Miocene age, poorly consolidated, well sorted and fine-grained with an average thickness of 86 ft. The oil had an 18 API and a viscosity of 21 cp at initial conditions. Oil production began in 1926 and more than 1,000 wells have been drilled. By December 1999, 36.7 % of the initial oil in place had been produced. Flank waterflooding, at an average water injection rate of 100,000 stb per day, was introduced for pressure maintenance purposes in 1984. Cumulative water injected was 558 million barrels by December 1999. This paper evaluates the flank waterflooding project in the Lagunillas 07 reservoir. The net oil recovery due to the flank waterflooding is estimated. The real time water front movement is determined with a front-tracking technique that uses fluid production data. The movement shows water fingering due to reservoir heterogeneity. A good match is obtained when the water front movement is cross-correlated with the petrophysical properties of the reservoir. Finally, the impact of the flank waterflooding on recovery factor is highlighted. The paper concludes that a net oil recovery of 17 million barrels can be attributed to the flank waterflooding from 1984 to 1999. A net oil recovery of 160 million barrels is expected if the flank waterflooding is continued until 2019. The flank waterflooding is therefore considered a success. A future development plan is proposed for the reservoir. Introduction The Lagunillas 07 reservoir is made up of a simple broad gentle arch structure with an average strike of 300° and a southwest dip of 3° to 3.5°. It consists of 3 units with cross flow and good vertical communication. The units are the Laguna, the Lagunillas Inferior and the La Rosa. The Laguna and the Lagunillas Inferior units consist of fluvio-deltaic sediments. There is sand continuity in both units. The Laguna unit is more complex with thinner, poorer quality and less continuous sands than the Lagunillas Inferior. The Laguna pinches out to the northeast. The Lagunillas Inferior unit contains the best oil sands and accounts for about 90% of all initial oil in place. The La Rosa unit is mainly marine and is more heterogeneous with less oil sands. The first well was drilled in 1926. Early production data was of poor quality. Subsidence data were not taken until 1940 although surface subsidence due to rock compaction had occurred earlier. Rock property data were obtained from 2 core analysis studies. Average porosity was 30% and connate water saturation was 16%. The reservoir temperature was 152°F. Field production History Oil production began in 1926 and reached a daily peak of 115,000 stock tank barrels (stb) per day in 1937. It fell to an average of 63,000 stb per day between 1938 and 1958 despite the installation of artificial lift. After 1958, the production rate became market dependent. The production rates steadily declined until it reached a low point of 16,000 stb per day in 1972. New infill wells were drilled and the oil production rate increased to 49,000 stb per day by 1980. A decline in the rate after 1980 prompted a study to determine the benefits of flank waterflooding as a response to declining average reservoir pressure. A flank waterflood was initiated in 1984 as recommended by the study. Figure 1 shows the daily oil production and the watercut. The watercut was in the 15% – 20% range between 1960 and 1980.
- Geology > Petroleum Play Type (0.74)
- Geology > Geological Subdiscipline > Geomechanics (0.74)
- Geology > Sedimentary Geology > Depositional Environment > Transitional Environment > Deltaic Environment (0.54)
- Geology > Rock Type > Sedimentary Rock (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.57)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Tia Juana Field (0.99)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Lagunillas Field (0.99)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Cabinas Field (0.99)
- (3 more...)
Reservoir Description Helps to Improve Stimulation Designs in Hot and Fissured Reservoirs in Mexico
Caldera, J.A. (Schlumberger Oil Field Services) | Centeno, G. Tellez (PEMEX Exploracion y Produccion) | Robles, F. Cazares (PEMEX Exploracion y Produccion) | Sobrino, J.C. (Schlumberger Oil Field Services) | Frass, M.O. (Schlumberger Oil Field Services)
Abstract Most of the reservoirs in Mexico are carbonate formations, which produce mainly from high conductivity fractures, the temperature of these fields generally goes above 140 C. Under this combined scenario of fissures and hot environments low rate acid injection generates a very fast mass transfer from acid to the rock, which yields very poor results in terms of production. Good results have been obtained on latest designs when injection rates have gone above frac pressure. The high rate mitigates the combined effect of the high proportion of rock surface area in the fissure to low volume of acid in the rock and the high temperature. Special acid systems as emulsified systems; organics acid and high strength acid have been used to complement this practice with excellent results. Gelled especial system has helped to obtain a homogenous distribution of the acid in the open intervals. Introduction Deep and hot carbonate formations are very common in Mexico, temperature in this hot fields can reach above 150 C, depth of this limestones and dolomites productive reservoirs are often deeper than 5000 mts. The most common operation in such fields is matrix-acidizing stimulation to improve well production. High temperature and heterogeneous distribution of rock properties are the main limitation that the operator has to face to obtain positive results after acidizing treatment. Generally it is believed that this reservoirs are naturally fractured with a very permeable and well connected network of fissures, however some times log response and transient test interpretation yields a different reservoir characterization where one or several fractures are the only mean of production in the whole reservoir thickness. Production models were used to match production history to verify that reservoir characterization from transient test is suitable and representative of these fissured wells. Based on this, a question arises in reference to what should be the stimulation strategy under this combined scenario of high temperature and fissured wells. The effectiveness of the acid is not the same under matrix injection into a one porosity medium than placing acid inside a hot fissure. This work presents a documentation of latest experiences where a multidisciplinary approach has helped to introduce reservoir characterization in the stimulation design. Naturally Fractured Reservoirs Typical double porosity response is not always seen on pressure transient test on fissured formations, the lambda and omega shaped curves will only appear un certain conditions of matrix permeability and fractures distribution, homogeneous and unfractured response could be observed if matrix permeability is equal or higher than fracture permeability or if the matrix has no permeability and the fractures are oriented in several directions. Linear flow can be observed if the matrix has no permeability and the main fissures are oriented in one particular direction. When linear flow is observed, a transient test allows characterizing those fractures. Fracture length and conductivity can be calculated and used in production modeling to match actual production data. Well A test shows linear flow with a 61 feet long fissure matched with an infinite conductivity fracture model (Fig. 1), fracture length and conductivity obtained from transient test could be used to calculate the theoretical production response of the well, matching the actual production data (554 bpd with Pwf: 4100 psia) (Fig. 2).
- North America > Mexico (1.00)
- Europe > Norway > Norwegian Sea (0.25)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.54)
- Geology > Geological Subdiscipline (0.35)
Abstract For many years, all the untreated production water from the Groningen gas field in The Netherlands had been injected into a dedicated water disposal well without problems. Recently, however, the injectivity of this well reduced significantly as a result of downhole blockages. Various remedial injection well clean ups and acidisations were executed without much long-lasting success. Early 2001, a dedicated study was conducted to identify the causes of the problems and come up with remedial actions. In particular, the question was whether the well plugging was due to the the low quality of the injection water, which would imply building dedicated water treatment faclities in order to remediate the problem, or whether the blockages were due to some other mechanism. By carrying out a thorough analysis of all the injection data over the years, and combining this analysis with water injection computer simulations, it was concluded that the injectivity problems had nothing to do with the low injection water quality, but were the result of sand production during shut-ins. This result appeared surprising at first sight as the disposal water is injected into a fairly competent sandstone. It led to a set of recommendations for an improved way of operating the disposal well. The recommendations have been followed up, as a result of which the well has been in operation trouble-free over the last six months. 1. Introduction For many years, untreated production water from the Groningen gas field has been injected into the Borgsweer-3 (BRW-3) water disposal well without problems. Recently, the injectivity of the well reduced significantly as a result of downhole blockages. Various remedial injection well clean ups were executed without much long-lasting success. All production water is collected in large settling tanks at the central processing facilities in the nearby town of Delfzijl. From there, the water is pumped via a 10 km GRE pipeline to Borgsweer. Fig. 1 schematically depicts the Borgsweer injection facility. A large tank (T4) is fed with production water from the Delfzijl facilities. The water can be injected into wells BRW-2 and BRW-3 via two different "modes": either by pumping (THP˜108 bar; injection rate ˜ 150–200 m3/hr) or by "free fall injection" via a pump bypass (THP ˜ 0.4 bar, determined by the water level in T4; injection rate ˜10 m3/hr). Switching between the two injection modes is controlled by the water level in T4. As soon as this level starts to exceed 90%, the pump bypass is closed, one of the injection pumps is switched on, and water is pumped into the two disposal wells (BRW-2 and BRW-3) until the T4 level has dropped to below 40%. At this moment the injection pump is switched off, the pump bypass is opened, and water is injected by "free fall" until the T4 level has risen to 90%, after which one of the pumps is switched on, etc. Fig. 2. illustrates the cyclic injection process. As can be seen, cycles can last from a few hours up to a few days, depending on the water supply rate from Delfzijl. Another thing to be noted is that in each pump cycle, the injectivity initially rises within a timeframe of a few hours to a maximum ‘steady-state’ value. This can be ascribed to the thermo-elastic effect: after switching to a high injection rate, the BHT slowly drops to a new equilibrium value, with its corresponding fracture propagation pressure and therefore well injectivity, see also Fig. 2.5 for comparison. The thermo-elastic phenomenon will be discussed more extensively below as part of the fracture simulations. 2. Mechanisms contributing to injectivity decline Fig. 3. shows a schematic overview of the BRW-3 completion diagram, together with the four different perforation intervals and their shooting dates. Indicated are the possible mechanisms contributing to BRW-3 injectivity decline, as identified during the Workshop. Each of these mechanisms will be discussed in more detail in the paragraphs below.
- Geology > Mineral > Silicate (0.96)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.30)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > Southern North Sea > Rotliegend Sandstone Formation (0.99)
- Europe > Netherlands > Groningen > Southern North Sea - Anglo Dutch Basin > Groningen License > Groningen Field > Upper Rotliegend Formation (0.99)
- Europe > Netherlands > Groningen > Southern North Sea - Anglo Dutch Basin > Groningen License > Groningen Field > Limburg Formation (0.99)