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Collaborating Authors
SPE Latin America Petroleum Engineering Conference
Abstract This paper presents a new system to improve safety and reliability of a gas treating plant. The geographic location of the plant, isolated on a hilltop in the subtropical jungle in the north of Argentina, increases the importance of this system. The entire system is handled by Programmable Logical Control, Programmable Logical Control, which takes its information from four different sources: Manual Shutdown, Gas Sensors, Ultraviolet/infrared Fire Detectors, and Data Acquisition System. It is a real time monitoring and control system. Input information is processed in the PLC and action is taken automatically in accordance with the results of the analysis. The system can take the following actions: Close the flowline valves from the wells, Open the vent valves, Cut off the energy supply, Stopping the gas and propane compressor, Turn on the propane compressor, Turn on the fire pumps, Shut down the furnaces, Activation of the alarms. The difference between this system and other systems in similar plants lies in its flexibility and speed which help to avoid unnecessary plant shutdowns. All the elements connected with the PLC are tested every two seconds. In the control house, there is a panel that can operate the system manually if there is a problem with the PLC. It also features a mimic with LED for each data source. The color of the LED indicates one of the following conditions: Normal operation, Caution, Changing condition, Alarm. Introduction The main risks incurred the operation of a natural gas treating plant are gas leaks, combustible vapors, fire and explosions. The application of codes and laws regulations to the design, the construction and the operation of these plants minimizes these types of risks but they do not fully prevent the occurrence of insuperable events. On the one hand, risks are increased by human mistakes and by inadequate maintenance of materials, which results in corrosion. P. 37
Introduction Horizontal drilling technology has become an economic reality, and the result has been a dramatic upsurge in the number of horizontal wells drilled. As the industry's experience of drilling, completing, and producing horizontal wells increases, so does the realization that horizontal technology is not always a solution to the problem of more cost-effective production. When evaluating the potential benefits of completing wells horizontally in a specific reservoir, the performance of the reservoir as well as the economics of drilling and completing the wells must be examined. No matter why a horizontal well is drilled, the decision to drill must come from results that analyze all reservoir data available. Technical success and economic failures already associated with horizontal wells over the last three years have brought home this point. GOALS FOR HORIZONTAL WELLS FROM A RESERVOIR PERSPECTIVE The main goals of horizontal drilling are 1) maximize the ultimate recovery factor, 2) maximize the economics of recoverable reserves, and 3) sustain a high production rate for as long as possible to optimize ultimate possible to optimize ultimate recovery. The main objective from a reservoir management basis is the best exploitation of petroleum resources in the development and production phases. This includes the production phases. This includes the prevention of non-economic prevention of non-economic developments (waste or well interference) and the maintenance of a flexible response to production opportunities. RESERVOIR DECISIONS TO DRILL HORIZONTALLY The primary questions to ask are:Why drill a horizontal well, and 2 What advantages does it offer? The majority of recent horizontal wells ere drilled because of expected productivity increases 2โ20 times productivity increases 2โ20 times higher over deviated or vertical wells. Generally, an improvement of about 2 to 2 1/2 times could provide sufficient economic justification for a well drilled horizontally. The chief reservoir reason to drill horizontally is for production improvement by greater exposure to a producing zone or zones. A producing zone or zones. A horizontal well may also offer other advantages such as 1) pressure drops and fluid velocities are less around the wellbore, 2) water and/or gas coning is minimized, and 3) production usually is accelerated. production usually is accelerated. Increased production of horizontal wells can reduce the number of wells required for infill or development and reduce the number and size of platforms and/or other structures platforms and/or other structures required in development stages. P. 29
Abstract A dual porosity simulator was used to evaluate the feasibility of drilling high angle slant wells in the naturally fractured cretaceous reservoir VLA-515, which is located in a geologically complex zone constituted by interconnected fractures where the risk and drilling costs are considerably high. Simulations were conducted to reproduce the existing reservoir conditions, and predictions were made to compare the performance of stimulated vertical wells with horizontal, and slant wells. The production potential predicted for the slant well was twice higher than the achieved by the vertical well, in addition of increasing the oil recovery by 3 %. Simulation results showed that the slant well will recover approximately 9 MMSTBO during the first 5 years, while the vertical well requires 11 years to obtain the same cumulative production. Finally, under the conditions of the VLA-515 cretaceous reservoir a 55 degrees slant well will achieve higher recovery than an horizontal and stimulated vertical wells, due to higher amount of contacted fractures as consequence of its penetration angle into the reservoir. Introduction Naturally fractured reservoirs are generally classified as dual porosity, where one porosity is associated with the matrix and the second represents the fractures storage capacity. In dual-porosity oil reservoirs, fractures provide the main path for fluid flow from the reservoir, then oil from the matrix flows into the fracture space and the fractures transport the oil to the wellbore. Maraven S.A, has been producing oil from the VLA-515 reservoir, which is located in a geologically complex zone formed by a network of interconnected fractures, where although there is a large volume of remaining oil, the risk and operational cost are considerable high. Consequently, in order to increase the reservoir recovery a technology that would allow the interception of grather quantity of fractures will be required. One of the most recent technological innovations on fracture reservoirs is the drilling of slant wells, which allow to contact a greater quantity of fractures (Ref.1). This work show results of simulations aimed to compare the Performance of a vertical well with and without stimulation versus an horizontal and slant wells (55 degrees) under the VLA-515 cretaceous reservoir conditions. RESERVOIR DESCRIPTION The VLA-515 reservoir is located in the West flank of block I, located in Lake Maracaibo, Venezuela. The reservoir is constituted by an anticline structure dipping between 25 to 30 degrees to the Southwest. The West flank structure has been related to the lateral movement of the Icotea fault system NNE-SSW. This fault has been considered the most important of Block I, and define the East limit of the West flank, which has been interpreted as a very fractured zone The reservoir sediments were deposited above a marine platform, and are constituted by three lithological platform, and are constituted by three lithological sections that were designated as formations Maraca, Lisure and Apon, and which are known as Cogollo group limestones. P. 19
Abstract Maraven S.A is considering to initiate a gas injection project in a large Md geologically complex volatile-oil project in a large Md geologically complex volatile-oil reservoir, located in Lake Maracaibo, Venezuela. This paper describes the methodology used to carry out sensitivities to evaluate the feasibility of using a pseudo compositional option of a black-oil simulator to conduct the 3-D simulations. The first task of the study was to decide whether geological complexities or phase behavior had a larger influence on reservoir performance. Therefore, 1-D sensibility runs were carried out using a fully compositional simulator, and a pseudo compositional simulator to compare compositional effects, grid-block size required to reduce numerical dispersion, effect of displacement pressure, Md the use of different injection gases. In the following phase, 2-D simulations were conducted to investigate the effects of heterogeneities on recovery, and the feasibility of lumping the sedimentological facies into flow units without modify the original sedimentological reservoir description. The results showed that the simulated behaviour with the pseudo-compositional simulator were more sensitive to pseudo-compositional simulator were more sensitive to grid-block size, and numerical dispersion. Also, indicated that adequately modelling of internal reservoir heterogeneities is quite relevant. The simulation results, allowed to observe that the pseudo compositional simulator formulation does not take into account the miscibility mechanism for multiple contacts of gas and reservoir oil. Also, at the current reservoir pressure small differences were observed in the results of pressure small differences were observed in the results of both models, Md large reductions in running time were obtained in the pseudo compositional runs. The previous results enhanced with the ability to permit a better description of the reservoir heterogeneities, indicated superiority of the pseudo compositional model to carry out the 3-D simulations. Introduction The Eocene C is a deep, large and geologically complex, volatile-oil reservoir, located in Lake Maracaibo, Venezuela. The structure is an elongated flank of 16 X 4 kilometers, with dip ranging from 2 to 5 degrees. The estimated STOIIP was 2100 MMSTB of a 48 degree API crude, and cumulative production for January 1989 was 210 MMSTB. Hydrocarbons are produced from 8 separate sands located between 12200 ft and 13700 ft. However, from a pressure standpoint, only two main sand-packages are recognized: C-4 and C-455/60. The later contains the bulk of STOIIP. The reservoir is composed of low permeability sands and a crude which composition is near to critical point. Since 1960 the reservoir has been producing by natural depletion, helped by a low aquifer activity. The reservoir pressure has declined from the initial value of 5900 psia to pressure has declined from the initial value of 5900 psia to the actual value of 3900 psia below the bubble point pressure (4200 psia). In order to avoid the reservoir pressure (4200 psia). In order to avoid the reservoir pressure decline, and considering the highly volatile oil pressure decline, and considering the highly volatile oil characteristics, and complex reservoir heterogeneities, it was decide to initiate a gas injection reservoir simulation study to optimize future exploitation polices. In the first part of the study, the phase behavior and compositional effects involve in the gas injection process were evaluated. In the following phase an evaluation of the requirements of the 3-D model was performed, regarding to the minimum number of layers need to simulate adequately the fluids movement into each flow unit. Base on this results, a 3-D reservoir simulation model will be developed to carry out predictions of future performance, and evaluation of alternative production options. THEORETICAL CONSIDERATIONS The oil reservoirs which initial conditions are closed to the critical point are known as volatile oil reservoirs. In a phase diagram those oils are closed to the gas condensates. phase diagram those oils are closed to the gas condensates. P. 25
- Geology > Sedimentary Geology (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Introduction The reservoir simulation is a technology of generalized use in the petroleum industry to evaluate actual and future reservoir performance. However, a general methodology for reservoir performance. However, a general methodology for reservoir simulation has not been completed defined in the literature. In view that reservoir simulation is a basic tool of reservoir management, Maraven S.A decided to standardize the procedures involved into a reservoir simulation study, procedures involved into a reservoir simulation study, developing a methodology aimed to eliminate engineering and computing time waste during the process of model initialization, history match, and predictions, which represent the main part of the reservoir simulation process. Consequently, work processes were established and documented including flow diagrams, and forms were prepared to obtain information, in order to keep track of the prepared to obtain information, in order to keep track of the time used during the execution of each stage of the processes, allowing to use statistic control to monitor each processes, allowing to use statistic control to monitor each process performance. process performance. The application of the developed methodology allowed to identify the main time consuming activities, optimizing the studies execution process by reducing the risk of overlooking key aspects and variables, thus increasing the level of confidence of the simulation results. Finally, the preliminary statistic control results have allowed to identify the following actions. 1) Guarantee the use of flow diagrams and measures of the time used in the execution of each process stage, 2) Develop automatic data processing and administration systems to accomplish the processing and administration systems to accomplish the simulator requirements, and 3) Continuous training in computerized tools. GENERAL METHODOLOGY The general methodology for reservoir simulation presented in this work, consisted of structuring into stages the process of initialization, history, match, and predictions. The aim was to provide new reservoir simulator predictions. The aim was to provide new reservoir simulator users with a detailed description of the activities (a series of actions and changes) involved in the execution of each of the main reservoir simulation processes. Figures 1, 2 and 3, shown the flow diagrams of each process. Detailed discussion of the different stages involved in each process will be presented next. PROCESS FOR INITIALIZATION OF THE PROCESS FOR INITIALIZATION OF THE RESERVOIR SIMULATION MODEL The initialization process consist of the reservoir model validation through the calculation of the original fluid in place volumes. The model initialization allow to establish place volumes. The model initialization allow to establish the initial fluid saturation and pressure distribution within the reservoir. The flow diagram presented in Figure l, show the procedure to carry out the initialization process for the hypothetical general case of a reservoir with a gas cap and water zone. A detail discussion of the different stages involved is presented next. presented next. 1. Preliminary initialization run The first run of the initialization data is conducted in order to check data entry format errors. As result the pressure, fluids saturation distribution, and fluid in place pressure, fluids saturation distribution, and fluid in place volumes for the different fluids inside the reservoir are obtained, i.e., the simulator interpreted initialization data. 2. Data entry verification Normally, the first initialization run of a simulation model may abort dub to errors in data entry formats, inconsistency of relative permeabilities and/or PVT data. The errors of initialization data are normally of the following types. Parametric problems, fluid properties tables, saturation Parametric problems, fluid properties tables, saturation tables, equilibrium condition tables, aquifer definition, and array generation. P. 35
- South America > Venezuela (0.28)
- North America > United States (0.28)
SPE Members Abstract In this work the fundamentals and theoretical principles are presented that describe a system used for both pressure data acquisition and analysis. The advantages of using equivalent time and pseudo equipment time in the plotting functions used for pressure transient analysis is explained. For pressure data analysis, the system automatically optimizes the reservoir parameters, resulting in a theoretical profile that matches the measured data with profile that matches the measured data with minimum standard deviation within the noise band of the measured data. Regarding calculation of reservoir parameters, the system calculates the value of the parameter by non linear regression using the entire test profile. The reservoir models included in the system are described and several field applications are presented. A main result derived from this work is that we can conduct an accurate test faster and reduce rig time using advanced plotting functions and regression techniques. Complex systems like layered reservoirs and horizontal wells can be handled by the system. Introduction Over the past 20 years, many systems for pressure transient analysis have been pressure transient analysis have been introduced to the oil industry. Each system has its own philosophy regarding data acquisitions and analysis. The advent of electronic pressure gauges definitely enhanced the reservoir description obtained through the analysis of the obtained data. The ultimate objectives of a well testing program are to acquire and analyse well program are to acquire and analyse well test data to obtain a complete description of the reservoir to allow the determination of an accurate cash flow of the well effluents. Well test objectives are usually classified as either short term or long term. Short term well test objectives are to gather and analyse sufficient data to obtain a description of the reservoir system in the vicinity of the wellbore. Long term well test objectives' are to gather and analyse sufficient data to obtain a complete description of the reservoir. The test objectives are obtained through data analysis. A common technique is to analyse the data using log-log type curve matching and semilog (Horner) type of analysis. Several aspects should be considered for a successful reservoir description: Pressure gauge resolution (sensitivity), data acquisition system, well test data quality and method of analysis. P. 31
SPE Members Abstract In this work a testing technique based on analysis of the pressure transient created by formation surging is presented. The application of the technique is focused to cases where the tested well has high water cut besides strong bottom hole water drive and partial penetration. The analysis of the flow regimes shown under these conditions is presented. Several field cases are shown in order to see the application of this technique. A major result derived from this study is that the technique can be successfully used in cases where by conventional pressure transient analysis no reservoir parameters can be obtained mainly because no radial flow is shown due to constant pressure effects. Linear, Radial, Bilinear and Spherical flow can be identified. Therefore making possible the calculation of transmissibility and skin effects. Introduction A common testing technique used in some fields for active or producing wells where there is a strong bottom water drive is the surge test. The objectives are to check well condition regarding production in order to design a semi-submergible electric pump. When surging an underbalance condition is created that will help cleaning the perforations. To avoid water conning effects perforations are located at the top of the formation. Production is characterized by high water cut. Conventional pressure transient analysis under strong bottom pressure transient analysis under strong bottom hole water drive is difficult specially due to the very short flow period and quick flowing pressure stabilization. Under other conditions pressure stabilization. Under other conditions a common buildup test is characterized by a flow period previous the shut in. Usually shutin period is 2 to 3 times longer than production or flow period. The Horner method for data analysis in the buildup period based on the following equation (1) The conditions of applicability of the Horner method are well known. In particular the appearance of the semilog straight line where from the slope the reservoir parameters can be calculated is always subject to controversies. Test duration not long enough, wellbore storage effects just to mention a few are factors that may impose limits to the application of the conventional Horner method. P. 7
SPE Members Abstract In this work, a brief summary is presented on the fundamental principles of multirate testing. The main objective is the analysis of several field cases where the technique has been successfully. in the determination of drainage area reserves. The method of solution is presented for pressure transient analysis and involves pressure transient analysis and involves the use of a numerical simulator in most of the cases for an optimum reservoir modeling. Examples of tests conducted in the Maracaibo Lake fields are presented. Based on several field cases, an efficient design of the multirate test in order to get the reservoir evaluation objectives was obtained. An extended flow rate period was added to the conventional way to conduct these tests resulting in a better reservoir description for the drainage area investigated. The results were used to determine the next development well in the field under study. Introduction It is very common to find the solutions for the transient wellbore pressure as predicted by a given reservoir model in predicted by a given reservoir model in the form of graphical displays also known as type curves. Typical solution shown is the wellbore flowing pressure for a well producing at a constant rate. From a producing at a constant rate. From a practical point of view, it is often practical point of view, it is often mentioned that to keep a constant flow rate is many times the exception and not the rule and build-up tests are more common than drawdown tests. According to the literature, type curves for drawdown test have been used to analyse buildup data. The assumptions and limitations have been also pointed out. With the advent of advanced testing production equipment that permits a controlled production during the test and also to high resolution pressure gauges it is possible to carry outs pressure gauges it is possible to carry outs pressure drawdown test with a high degree pressure drawdown test with a high degree of confidence for the obtained results. also and it is the case treated in this paper, drawdown tests in the form of paper, drawdown tests in the form of multirate test are preferred in cases where shutting in the well is not convenient due to differed production. It is the objective of this work to show that multirate tests can be successfully implemented from an operational point of view and that by adding an extended flow period, a complete evaluation for the well/reservoir system is obtained. IPR and dynamic reserves associated to the drainage area of the well are obtained results from multirate analysis. P. 21
SPE Members Abstract In this work the advances in pressure transient data acquisition and analysis of pumping wells are presented. A brief summary is presented on methods used in the past 20 presented on methods used in the past 20 years for testing pumping wells. A comparison is made between pressure data acquired using bottom hole gauges and that based on indirect calculation of the bottom hole pressure by determining the liquid level in the annulus acoustically measuring the surface annulus pressure, and calculating the bottomhole pressure, and calculating the bottomhole transient pressure. The quality of the acquired data using the previously mentioned method is the main topic of discussion and its use and/or limitations for reservoir and well evaluation. Several field examples are used to illustrate the presented methods. As a main result it is concluded that pressure data acquisition using acoustic methods is the best alternative for pumping wells. The pressure data resolution and accuracy is pressure data resolution and accuracy is similar to a conventional amerada type of gauge. However the main advantage is that we can get the whole pressure transient profile (flowing/buildup) in real time if necessary. This definitely provides an enhanced data interpretation that can be used for reservoir evaluation specially for secondary recovery projects. projects Introduction Formation evaluation using pressure transient analysis is a well known technology applicable to both exploratory as well as production or active wells. Recent advances in the theoretical principles for the analysis of pressure transient principles for the analysis of pressure transient data and in the resolution of pressure gauges permits a resolutive reservoir description for permits a resolutive reservoir description for the drainage area of the well tested. A good summary of the advances in practical well test analysis has been recently presented by Ramey. Much of the advances have been obtained during the eighties: Use of the derivative as a diagnostic tool, regression analysis techniques for data evaluation are just a few. Nevertheless and in spite of the recent advances there are many cases where a given analysis is subject to uncertainties and spec. It seems that both the reservoir model used to match the data and the particular well production system are factors that sometimes limit the acquisition and analysis of data. A good example of this are pumping wells. It is worth to mention here that there are many secondary recovery projects where production comes from pumping wells. Pressure production comes from pumping wells. Pressure monitoring using conventional amerada gauges is not quite accepted due to uncertainties in the measured wellbore flowing pressure just before shut-in. In many cases because of the lack of data during the early time region of the buildup period. P. 19
- Overview (0.34)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
SPE Members Abstract In this paper, a brief description is given to operational procedure involved in acquiring transient data using a down hole shut-in tool. Field cases (Maracaibo Lake are presented to show the advantages of this technique in active wells and for cases where reservoir pressure is below bubble point. A comparison is made between this technique and the one that is based on simultaneous measurements of transient flow rate and pressure. The benefits both from an economic point of view and from the reservoir evaluation side using this method are presented. A main result derived from this work is that the use of the down hole shut-in tool reduced the build-up time by a factor of 10 in some cases for tests conducted in Maracaibo Lake fields. A considerable saving in differed oil production was gained besides the benefits of having pressure transient data not strongly affected by wellbore storage and phase segregation which permits a better reservoir evaluation. Introduction Reservoir description using pressure transient analysis is a well known and established methodology. Recent advances, both in reservoir models and equipment resolution for field well testing, show that successful reservoir evaluation results can be obtained if appropriate test equipment is used to reach the objectives. In the area of pressure transient data analysis, significant improvements have been reached, such as the use of the pressure derivative as a flow regime diagnostic tool and the regression both linear and non linear for the overall pressure profile analysis. Even though we are still faced with the inverse problem that is to say different models problem that is to say different models can match the same pressure transient data the use of the computer and the numerical simulation approach will definitely help in choosing the right reservoir model to match. In the area of testing equipment and pressure gauges with the advent of quartz type of gauges, a resolution as low as 0.01 psig can be easily obtained. This type of gauge is commonly used in may tests. Regarding equipment for testing, advances have been reached when testing exploratory wells (DST type of tests). Deeper formations and temperatures above 300 degrees F are tested every day and they pose a challenge regarding equipment performance. P. 7
- South America > Venezuela > Zulia > Maracaibo (0.45)
- North America > United States > Texas > Dawson County (0.34)