The most common problem during the sand control operation is fluid loss. It is an inherent problem encountered worldwide, due to the high permeability of sandstone reservoirs which allows easy fluid flow into the formation matrix. Many wells which are candidates for sand control produce from marginal reservoirs and have insufficient bottomhole pressures to support a column of fluid in the wellbore. Still other wells with high pressure zones require high density completion fluids in order to balance the reservoir pressure during the gravel pack operation. In either case the positive pressure leads to fluid being lost to the pressure leads to fluid being lost to the reservoir. The result presents several potential problems: (1) formation damage potential problems: (1) formation damage caused by swelling of clay minerals within the formation, (2) formation damage due to particle invasion into the formation (3) particle invasion into the formation (3) formation damage due to dissolution of matrix cementation promoting migration of fines within the formation (4) flow channel blockage by precipitates caused by ionic interactions between well servicing fluids and formation fluids (5) interactions between well servicing fluids and formation fluids causing emulsion blocks, water block,, or changes in wettability of a producing sand and (6) flow channel producing sand and (6) flow channel blockage due to viscous fluids creating a barrier in the near wellbore region. The need for mechanical fluid loss control systems in these situations is, therefore, obvious.
During many sand control operations the standard procedure is to acidize the formation prior to gravel packing, thus increasing the near wellbore permeability. Then it is recommended that the acid treatment be followed immediately with the gravel pack treatment until a sandout occurs. After gravel packing, the wellbore is frequently in a lost circulation condition. This requires either keeping the hole full, resulting in large volumes of fluid lost to the formation, or unknowingly spotting an inappropriate fluid loss pill. Both options can result in formation damage and excessive costs.
One important goal in reservoir testing is to determine the reservoir characteristics and the well's productivity. Measurements which can contribute to this goal include well logging, fluid sampling, pressure transient testing, and production profiling. A careful analysis of these measured production profiling. A careful analysis of these measured data will provide adequate information for well evaluation. The purpose of this paper is to show how an integrated reservoir purpose of this paper is to show how an integrated reservoir testing methodology in conjunction with a human engineered procedure on computer enhances the reservoir characterization procedure on computer enhances the reservoir characterization and the evaluation of well performance.
This integrated methodology includes concepts, which have been implemented in recent approaches to reservoir testing and NODAL* analysis. During the design phase of each test, sensitivity studies provide insights that facilitate adequate data gathering for valid interpretation, which can help minimize the cost of the test. During interpretation, the central issue is to identify a realistic reservoir model which reflects the transient pressure and rate behavior. Here significant use is made of the log-log plot of pressure change and its derivative with respect to superposition time. Systematic diagnosis of the log-log plot helps identify different flow regimes, while specialized plots and type curve analysis provide a basis for the estimation of reservoir parameters. Lastly, the computed results can be easily integrated into a NODAL analysis to study and evaluate the well's productivity.
The examples presented illustrate the benefits of a systematic approach to reservoir test design and interpretation, and well productivity evaluation. The computer procedure also has the advantage of incorporating input data from several sources, including openhole logs and the Repeat Formation Tester (RFT*) tool.
During well testing operations, pressure, flow-rate and temperature transients are generally recorded using testing devices and the Production Logging tools (PLT). With the tools in a stationary position in the wellbore, the transient behavior of the reservoir is observed by varying the surface flow-rates. On the other hand, under stabilized and shut-in conditions, production logging measurements are conducted versus depth. Interpretation of these different types of data help the engineer to quantify the well/reservoir model, and to diagnose well performance.
The methodology outlined in this paper integrates a test design approach, currently acceptable acquisition procedures, interpretation techniques and NODAL analysis. procedures, interpretation techniques and NODAL analysis. For both vertical and horizontal wells, the interpretation procedures include the log-log presentation, the use of procedures include the log-log presentation, the use of pressure derivative for identifying dominant flow regimes, pressure derivative for identifying dominant flow regimes, convolution type curves and the convolution derivative when downhole flow-rates are available, and an automatic parameter estimation. Lastly, the integrated reservoir parameter estimation. Lastly, the integrated reservoir engineered methodology shows how interpreted results can be easily utilized to evaluate the performance of a well via NODAL analysis./
Several examples are presented to illustrate how the integrated methodology of test design, data acquisition, interpretation and well evaluation was encapsulated into a human engineered computer environment. The first example illustrates the advantage of downhole shut-in during a buildup test. The second example illustrates how different aspects of the interpretation procedure aid in evaluating late time effects. The next example demonstrates the transient response of a horizontal well test, the flow regimes that occured and the analysis thereof. Lastly, the evaluation of the horizontal well performance is compared with that of a vertical well using the NODAL analysis.
This paper confirms the high P friction in the production section of a horizontal well as proposed by Dikken. Available pressure transient data validates his theoretical pressure drops which are significantly greater than previously thought.
Due to short production intervals in most conventional wells (relative to horizontal wells) the phenomenon has minor impact on the conventional well. It can, however, play a significant role in the distribution of production in play a significant role in the distribution of production in a horizontal well and needs to be considered when running reservoir models to properly evaluate reservoir performance. Because of the risks and costs associated performance. Because of the risks and costs associated with production logging it is not generally detected.
This simulation work uses pseudo reduced pipe diameters in ECL's Eclipse reservoir simulator. They generate pressure profiles along the horizontal producing section that match Dikken's pressure producing section that match Dikken's pressure profiles. Eclipse simulator results indicate that friction profiles. Eclipse simulator results indicate that friction loss along the production interval has an impact on coning performance.
Results, Observations and Conclusions: 1. The increased P friction loss as predicted by Dikken has been verified by pressure profile data taken along the producing horizontal sections of a flowing well plus data from a step rate test on a second horizontal well. Continual inflow of fluid along the horizontal creates turbulence at lower flow rates resulting in significantly higher P friction loss.
2. Typically simulators calculate the P friction of the horizontal section by the same methods used to calculate P friction loss from flow through a pipe. They do not handle the P friction loss correctly in the horizontal production section and they tend to generate more uniform production profiles than found in the real world.
3. Incorrect pressure profiles yield inaccurate simulator results which may either be optimistic or pessimistic depending on the configuration of the well in the reservoir. Errors in the simulator results are more common in undamaged reservoirs with higher flow rates, high permeability and low viscosity.
4. Using pseudo diameters (reduced from the actual production liner diameter), existing simulators can generate a correct pressure profile along the horizontal well's production interval.
5. Increased simulator accuracy results where the horizontal wellbore pressure profile correctly represents the actual conditions. This improves the accuracy of horizontal prospect evaluations as well as the analysis of the performance of existing wells.
6. In water drive reservoirs, the performance of high angle wells (85 deg.+) can benefit from the phenomenon of skewing production to the front end of the well.
7. In reservoirs with a gas cap, production skewing to the front end of the horizontal can be detrimental to the performance. However, in this environment, the inverted high angle well (the beginning of the production section deeper in the reservoir and the end structurally higher) takes advantage of the production skewing phenomenon.
8. The completion design [well type (high angle, horizontal, inverted high angle); liner diameter; and perforation length] has a significant impact on well performance.
This work explores the application of automated pressure transient test analysis and deconvolution technique in laboratory scale. To achieve this, a linear core which provides a pressure response corresponding to predetermined mathematical models, has been constructed. The pressure response to applied boundary conditions has been monitored in real-time by means of an A/D converter installed in a microcomputer. Applying specific analysis techniques, permeability (k) and compressibility-porosity product ( ct) can be obtained from experimental data. Data analysis includes:
* deconvolution of accumulated production and pressure responses, i.e. the desuperposition of a variable boundary condition;
* least squares nonlinear estimation of system parameters. Greenstadt's modification of classical Newton's method has been selected to perform parameters optimization.
In order to be a reference to related future experiments, practical aspects and problems associated with the materialization practical aspects and problems associated with the materialization of this experiment, specially those related with the interface between physical experiment and computer techniques, are extensively detailed in this work.
Well and reservoir parameters, such as permeability, productivity and initial pressure, can be obtained through the analysis of pressure transient tests. Sometimes it is possible to detect pressure transient tests. Sometimes it is possible to detect reservoir heterogeneities such as permeability barriers, reservoir boundaries and natural fractures. Methods commonly used for interpretation of pressure data obtained in well tests consider analytic solutions of the diffusivity equation:
in which a constant sandface-rate is assumed as internal boundary condition. These methods, although very simple to apply, depend mainly on the ability to maintain a constant sandface rate during the test. And this is often almost impossible, due to the presence of wellbore storage effects. Using Duhamel's superposition theorem, it is possible to obtain the pressure response to a variable sandface-rate test. According to this theorem, the variable rate response is given by the convolution of the constant rate solution and the variable internal boundary condition (i.e. the variable sandface-rate). The inverse problem is known as deconvolution and can be defined as the desuperposition of the variable internal-boundary-condition. Applying deconvolution techniques and with the appropriate tools to measure simultaneously pressure and flow rate, corresponding constant-rate pressure response can be computed. Once collected data are available, pressure response analysis is performed in order to obtain the desired parameters of the well/reservoir system. This analysis is generally performed on a linear-regression-basis, using scales such as log-log, semi-log, Cartesian. System parameters or part of them can be calculated using the straight-line slope and its y-axis intercept. Depending on the selected mathematical model, type curve fitting may be required. As this task is generally performed manually, a high degree of subjectivity is inherent to this type of interpretation.
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.
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.
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.
A study of the geology, the pressure data, and transient pressure tests from the Ramos Field in Northern Argentina suggest that the reserve of gas-in-place is probably 100 x 10 standard cubic meters. However, the gas is probably not contained in the Santa Rosa sandstone formation from which is produced. Rather it is probably contained in the shale zones which overlie and underlie probably contained in the shale zones which overlie and underlie this formation. The fracture system throughout the Santa Rosa sandstone is the conduit through which the gas is carried from the shales to the wells.
If this analysis is correct it means that any injected dry gas into the wells in the field will cycle very rapidly to the producers, because the pore volume of the fracture system is only a small fraction of the volume containing the gas. The available data indicate that the fracture system contains between .01 and .001 of the total gas indicated by a plot of P/Z versus the volume produced. The evidence is sufficient to caution the operator regarding the implementation of a dry gas cycling scheme which might be used to speed the recovery of the liquids contained in the gas condensate.
Pluspetrol S.A., Techpetrol, S.A. and Astra C.A.P.S.A. produce a Pluspetrol S.A., Techpetrol, S.A. and Astra C.A.P.S.A. produce a slightly wet gas from a sandstone interval deeper than 2800 meters in the Ramos Field in Argentina (See Figure 1).
The other two working interest owners are Astra CAPSA and Techpetrol S.A. These operators required an analysis of the producing mechanisms of the field to evaluate the possibility of dry producing mechanisms of the field to evaluate the possibility of dry gas cycling to speed the recovery of the liquids in the condensate.
The main productive unit of the field is the Devonian "B" (Santa Rosa) interval, commonly 330 meters thick and largely sandstone. The gas is trapped in a narrow, but elongate doubly plunging anticline in the foothills of the Andes. Petrographic and SEM examinations have indicated a plausible temperature and fracture history which suggests that no matrix porosity exists in the sand reservoir and that the fracture storage is unknown. Overpressured zones have been noticed in the overlying Los Monos shale, but not within the productive section.
The paper reviews the geological evidence and the transient pressure measurement results which have contributed toward the pressure measurement results which have contributed toward the conclusion mentioned above in the abstract.
Pluspetrol has produced a slightly wet gas from a sandstone interval Pluspetrol has produced a slightly wet gas from a sandstone interval deeper than 2800 meters in the Ramos Field of Argentina. The productive interval is referred to as the Devonian "B" or Santa Rosa productive interval is referred to as the Devonian "B" or Santa Rosa formation.
Satellite imagery indicates the field to be a narrow (5 km) but elongate (18 km) doubly plunging anticline trending north-south. The field is located very close to the Bolivian border, and may have an extension of some 8 kilometers north of a suspected fault at the end of the main structure northern plunge. The flanks dip about 45 degrees (See Figure 2).
This paper presents the exploration/development of the Rio Caribe field, the new technological frontier of the Venezuelan oil industry. This field comprises 26 prospects extended on a surface of 101123 acres (405 Kms) and Is part of a giant gas and condensate field discoveries in north of Peninsula of Paria. The other fields are Mejillones, Patao and Dragon discovered as a result of the exploration campaign realized by Lagoven, S.A. between 1979-1983.
The proposed strategy will be developed in several phases indicated by an early development of the proved area and combined by an extensive effort of exploration. The very first exploitation scheme selected is recycling dry gas in order to maintain the well potential, to improve the recovery factor and to offer an early policy for the gas management.
The area is located 25 Kms offshore of-the Paria Peninsula in the eastern Venezuela (fig. 1). Drilling of two explorations wells during 1982-1983 led to the discovery of the very first reservoirs (4B and 6B for the well RC-1, 4A and 6A for the well RC-2). These wells found gas condensate accumulations at a depth of 7.800 feet, of Pliocene age. The reservoirs were geologically classified as deep water fans deposits.
Later in the eighties, interspaced seismic shooting and geophysical interpretation identified 26 prospects in the same geological prospects in the same geological sequence.
It is currently estimated that the Rio Caribe contains 1.4 TSCF as proved gas original in place (with proved gas original in place (with 145 MMSTBS of 56 deg. API associated condensate). The present estimation represents less than 20% of the expected hydrocarbon accumulation.
Therefore this area was classified as highly prospective for exploration and development of gas and condensate projects.
During 1991, the Rio Caribe area was part of a giant seismic offshore shooting that covered the main gas prospective zone of the north of Paria Peninsula.
The expansion plans of the Venezuelan national oil industry envision an appreciable increase in the volumes of oil to be produced from Eastern Venezuela. As a consequence, the affiliate company Corpoven S.A. has deemed it advisable to develop a simulation model (MOSAYCO) of the production, transportation, storage and loading system of that region, which would assist in analyzing different options that arise when implementing said expansion plans. This paper describes the system handled by Corpoven S.A., the simulation model developed in SLAM II language and also, some of the results obtained by the use of the model. It is concluded that there is need to modify and amplify the operational infrastructure so that the system be better adapted during the execution of the expansion plans.
The National oil, petrochemical and Coal industry (IPPCN) envisions in its expansion plans an appreciable increase in the plans an appreciable increase in the production of crude from Eastern Venezuela. production of crude from Eastern Venezuela. This applies both to traditional areas and to new development areas such as those in the northern parts of the states of Anzoategui and Monagas.
In addition, IPPCN has, as a medium range goal, the consolidation of the development of the prolific accumulations in the Orinoco Bitumen Belt. Extraction from that area may be achieved by producing crude followed by refining in Venezuela or elsewhere and additionally, by converting the abundant bitumens available there into the new fuel which goes under the trade mark name of Orimulsion.
The oil system of Eastern Venezuela is a complex world of installations and operations which requires an integral analysis of all its components to detect its strengths and weaknesses. For this reason, Corpoven S. A. deemed it advisable to develop an apt simulation model (MOSAYCO) of the production, transportation, storage and loading system of that region. Clearly, such a model is in essence a planning tool that may be used to perform studies involving changes in the perform studies involving changes in the system without affecting at all the existing infrastructure.
Currently, the MOSAYCO model is a reality and it is being used in conceptual engineering studies to assist the company in the processes of decision making. These studies processes of decision making. These studies are of course tied in to the problem of defining the modifications to be made to the existing infrastructure of the production system so that it handle, under strict criteria of operational feasibility and economic efficiency, the increased volumes of crude which will be produced from Eastern Venezuela in the medium term.
The general objective of this project is to formulate a simulation model of the crude production system which is operated by production system which is operated by Corpoven S. A. in Eastern Venezuela. The model is to be used as tool to assist in the planning studies of infrastructure which the planning studies of infrastructure which the company carries out.
The model should take into account major production installations and processing of production installations and processing of crudes, operational procedures for handling said production and finally, programming of the fleet of tankers which dock at the oil port of Guaraguao to be loaded with crude and port of Guaraguao to be loaded with crude and refined products.
Using as data base a group of correlations generated from Eastern Venezuela PVT Laboratory experiments, a group of "minimum limiting conditions" based on simple field production measurements are proposed which, production measurements are proposed which, when met simultaneously, guarantee that the produced fluid stream is a gas condensate at reservoir conditions. It was also concluded that for each of the selected production parameters there is a "Transition Zone parameters there is a "Transition Zone in which the production stream can be a volatile oil or a gas condensate at reservoir conditions. It is concluded that the proposed method to define the existance of such gas condensates is very important for Eastern Venezuela since it expands the typical ranges that several authors have indicated to clasify the produced fluids as gas condensates at reservoir conditions.
In the process of studying the Eastern Venezuela reservoirs it is a very common situation to have the need to achieve adequate characterization of the phase behavior for the fluids originally in place in such reservoirs. In many fluids cases for the Traditional Producing Areas, the first issue to be resolved is to define if the produced fluid is a conventional black oil, volatile oil, or gas condensate.
The main objective of this paper is to present a method to delimiter the type of fluids at initial reservoir conditions. Since the proposed method or procedure is proposed method or procedure is based on common production parameters of the petroleum industry, parameters of the petroleum industry, the engineers can easily define the nature of the fluids in each case under review.
This method is proposed after a comprenhensive literature search as well an in-depth review of a significant group of PVT laboratory experiments available for Eastern Venezuela.
This study describes experiments and techniques relative to the control of solids and fluids used for deep well drilling, in the Marajo Basin, in the Amazon area, in Brazil, where the well bottom temperatures reach around 148,9 degree C(300 deg.F).
The solids removal system associated to a low solids fluid, non disperse, without densifier, basically composed of bentonite/polyacrylamide/potash have been considered as important factors for drilling with density inferior to 1080 kg/m (9.0 lb/gal), during all phases of the drilling process.
In the end of the 70's, the Drilling-DCW magazine published the results of a statistical survey about the 20 items of greater development concerning drilling, in the oil industry, for the last four decades. Most of the companies surveyed chose the bit technology as the number one item. The evolution of the drilling fluids and of the solids removal equipment were mentioned as the second most important item, since they were the starting point for the development of solids low content fluids. point for the development of solids low content fluids. Consequently, there has been some improvement concerning the penetration rate and the costs. penetration rate and the costs. Ten years have passed since such survey, probably some changes have taken place concerning that study. At present, for example, there is a great concern with life, man and the environment. The ecological unbalance concerns all the technological industrial fields. This fact, however, ratifies the emphasis given to the search for efficient systems of solids removal, the treatment of drilling fluids and of their effluents as well, and also the development of a toxic, harmless and non pollutant fluids, which have been in evidence in the end of the pollutant fluids, which have been in evidence in the end of the last decade. This tendency shall continue through the 90's, without disregarding the importance of the penetration rate and the operating costs.
Solids removal, dilution and chemicals addition are the three capital operations involved in processing the drilling fluid. Usually, these operations are meant to adjust or to maintain the fluids properties within acceptable ranges, to achieve the drilling goal at the lowest possible cost. Although the fluid treatment involves more than simple solids control, it is the critical operation of the process, according to many studies An inefficient solids removal system, shall end up increasing the fluid's density, viscosity and solids content. Dilution is unavoidable to keep the properties within the desired range. This process implies also increasing the effluents volume and the additives consumption. This situation is very common in the first stages of drilling. It reduces the costs of solids removal equipment rent, wear and maintenance.