The Frade project is Chevron's recently announced (June, 2006) deepwater heavy-oil sanctioned development project requiring a capital investment of approximately $2.5B. The development project is located in the northern Campos Basin juxtaposed to Petrobras's Albacore Leste and Roncador developments. First oil for Frade is scheduled for Q1 2009.
Frade, being a deep water heavy oil development project, has historically been both technically and economically challenged. The inherent subsurface and surface complexities alone might have shelved the development of this asset - particularly in the early evaluation period. Moreover, the fiscal and political landscape in Brazil has proven to be less than predictable further providing additional obstacles to project success.
After merging with Texaco in 2001, Chevron realized that a different approach would be required to assess the true value of the Frade asset, and initiated a systematic and standardized asset valuation process for Frade as part of its worldwide portfolio management exercise.
This paper will review the manner in which the development concept evolved from full-field platform to phased subsea as a consequence of employing tried and true business and technical processes that integrate G&G, reservoir engineering, drilling, decision analyses, and surface facilities. In particular, we will address one of the principle elements of Chevron's asset evaluation process - the Peer Assist - as it was employed at Frade along with resulting workplan and results.
The paper is a case history describing the progression of the Frade project from a marginally economic asset to the foundation of Chevron's deepwater Brazil portfolio. The focus of the paper will describe the approach used by the Frade Project Team to facilitate better decision making at critical stages of project development. Key elements of the approach involve:
Finally, we will show how robust Front End Loading (FEL) is critical to drive high quality investment decisions - specifically in marginally economic projects similar to Frade.
A case history is presented of the evolution of Chevron's Frade development asset through the company's asset management system. For the sake of this discussion, the paper will bracket 3 discreet timeframes or series of events that encapsulate the prevailing thinking of the respective subsurface teams working on the project at those times: pre-Peer Assist timeframe, Peer Assist sessions, and the post-Peer Assist timeframe (figure 1).
The main objective of this paper is to describe the integrated management process in Namorado field, a shallow water field in Campos Basin, Brazilian continental margin consisting on a multidisciplinary planning, a comprehensive diagnosis of the problems and a full set of corrective actions.
The steps include tools as wireline production and saturation logs, pressure and production tests, a suitable schedule of tubing changes, perforations in unshot oil intervals and abandon of swept intervals.
Moreover, a rigorous control of mass balance on injected and produced volumes is performed, as a permanent concern of the whole production asset, resulting in a politics of gradual increase in injected water volume and, consequently, an increment in the oil production.
It also includes periodic squeezes of an inhibitor in order to prevent Barium sulfate scaling and changes in the drainage strategy as the convertion of wells from producers to injectors and vice versa.
This management is performed by an integrated teamwork: Reservoir, Production, Workover, Lifting and Economics. It has shown remarkable results as the maintainance of the oil production and the reservoir pressure at the same level during the last twelve years.
Namorado field is located in the central portion of Campos Basin at water depths from 120 to 270m and is about 80 km distant from the São Tomé Cape, in the Northern coast of the Rio de Janeiro State, Brazil.
Discovered in December 1975 by the wildcat 1-RJS-19, the accumulation was satisfactorily delimited by twelve appraisal wells in the ten subsequent years.
The development phase of the concession occurred from 1983 to 1989 and involved the drilling of 48 wells, four of them were not used due to operational problems. Now, among the 33 producing wells, there are 30 wells with dry Christmas tree and 3 satellite wells with wet Christmas tree.
The oil production began in 1979 by a temporary production system to a FPSO. The definitive system, implemented after 1983, consists of two fixed platforms - PNA-1 and PNA-2, the first one with 10 oil producers and six water injectors, the second with 23 oil producers, three water injectors and one gas injector.
Initially, Namorado reservoir presented solution gas as primary production drive. In order to increase the recovery factor, in 1984 it was implemented seawater injection as a secondary recovery mechanism and also gas injection after 1997.
The lifting method is mainly gas lift and there are few surgent wells. The oil is then transfered to the continent through PGP-1 platform (Garoupa field), while the gas flows directly to the continent through a large pipeline.
The main reservoir, informally named Namorado Sandstone, belongs to the Upper Albian-Cenomanian transgressive sequence of Macaé Formation. It corresponds to clean sandstones, medium to coarse grained, predominantly massive, amalgamated up to 150m of thickness, deposited by turbidity currents in a background environment of sedimentation of marls and calcilutites1.
The reservoir presents a domic structure dipping to the North and to the East and pinching out to the North and to the South, as shown in the map of the Figure 1.
The presence of NW/SE faults compartimentalizes the field in at least three structural blocks (from West to East): the main, the adjacent and the marginal one, as seen in Figure 2. This structural model of assigned blocks is confirmed by the detection of several oil/water contacts. During the subsequent depletion of the reservoir, all blocks have shown pressure and fluid communication.
In almost all wells, it is possible to recognize three sequences of amalgamated turbiditic sandstones separated by discontinuous sequences of marls. Wireline formation tests in the development wells pointed out that the three sequences have a differential depletion among them (5 to 10 kgf/cm2), characterizing a small level of reservoir heterogeneity.
The challenge of the alpha/beta waves gravel packing open hole in offshore Brazil is how to successfully displace the proppant slurry in a large wellbore with a low fracture gradient formation, deep to ultra-deep water depths, and extended reach horizontal section.
Since 2001, job data from more than 72 open hole horizontal gravel packings have been compiled into a database. This paper reviews the well information and the key gravel packing parameters: pump rate, fluid density, injection proppant concentration, inner/outer annulus area ratio, dune ratio, packing rate, packing time and packing efficiency during alpha/beta waves. The engineering implementations and challenges, the best practices and lessons learned for open hole horizontal gravel packing are also summarized. The data analysis yields a better understanding about the open hole horizontal gravel packing in the Brazil offshore and provides a good guideline for future practice. A historical review is also presented showing how the gravel packing methodology has improved packing efficiency and success rate.
Case histories are provided demonstrating how to deploy the single trip system and pack the extended reach wellbore utilizing ultra-light-weight (ULW) proppant under extreme with improved packing efficiency and the success rate.
Deepwater exploration and production has developed over the last decade. There is a broadening of the geographic regions for deepwater completions (figure 1). The vast majority of the deepwater reserves are concentrated in the Gulf of Mexico, West Africa, Brazil, North Sea and South East Asia. The potential to achieve significantly higher sustainable production rates, well longevity and cost reduction have been the primary drivers for pursuing most deepwater completions. There have been many different types of completions in deepwater, however, the frac-packs and open hole horizontal completions have emerged as the two dominant completions. Appropriate applications are area dependent. In Brazil, the dominant completion type is the open hole horizontal gravel packing. In the Gulf of Mexico, 60% to 70% of completions are frac-packs. In West Africa both open hole completions and frac-packs are used.
Based on published references 3 to 19, open hole horizontal gravel packing envelops, in terms of depth and the hole departure, are plotted in figures 2 and 3. The latest world record horizontal gravel pack was completed in a well with the departure length of 4206m and a departure ratio of 5 in the Captain Field in the North Sea.13 The open hole horizontal gravel packing completed in the deepest well was in the Campos Basin field of Brazil with sub-sea TMD of 5093m and TVD 3855m.
Typical reservoirs in Campos Basin fields are high permeability turbidite sandstones with low API gravity oil. Generally, these unconsolidated formations are not strongly water driven. A high rate injection was needed to maintain reservoir pressure on these large producers. Several fields in the Campos Basin were developed with a series of horizontal producers and injectors.
More than 200 open hole horizontal gravel packings have been completed since 1998 in Brail1,2. Current gravel packing technology offers a good option for horizontal well completions where the problem is sand production.
Key issues in project planning and execution of open hole horizontal gravel packing include reservoir study, shale stability study, formation integrity test, gravel pack sand sizing, gravel pack screen selection, workstring design, well displacement, and fluid loss control. The feasibility and success of gravel packing a long horizontal well depends on drilling techniques, drill-in fluids, wellbore clean-up, completions fluids, completion tools, equipment, sand control techniques, software/simulators, pumping schedules and field personnel experience.
Challenges that can jeopardize performance of successful open hole horizontal gravel packing are excessive fluid loss, varying hole geometry that can lead to premature pack termination, hole stability issues leading to hole collapse, and a narrow pressure window between bottomhole pressure and fracture gradient. The beta-wave placement pressure is the main factor in determining the maximum length of a horizontal gravel pack. This pressure is limited by the requirement to install the gravel pack without exceeding formation fraction pressure.
Deep offshore oil production demands very high investments (CAPEX) so its development must rely on a careful planning. This frequently takes place in a setting with very limited amount of information due to high costs of appraisal operations. The figure becomes even more complicated when heavy oils are the target: low energy reservoirs require water flooding which, in turn, reflects in low recoveries and excessive water handling, not to mention other production problems.
This paper highlights different simulation studies that have been performed in order to set up an economical development plan for a 16 API 1700m water depth oil reservoir offshore Campos Basin. The main reservoir consists of a high thickness turbidite channel crossed by a N-S fault whose hydraulic conductivity is the main uncertainty. Vertically the reservoir is composed of three zones, where the upper one has a gas cap partially in contact with the two bottom ones. These structural complexities required a detailed study for positioning injectors and horizontal producers based on a decision tree analysis. The impact of other uncertainty variables was also identified and studied: horizontal permeability, vertical to horizontal permeability ratio, water-oil relative permeability and productivity index. Particular attention was given to the injectivity decline due to the planned produced water re-injection. Vertical and horizontal injection wells performances were compared in a scenario under strict geomechanical restrictions. The simulation model was also used to evaluate the possibility of developing marginal areas close to the main reservoir body.
The study leaded to a robust strategy for the water injection scheme. Risk and marginal reservoir analysis helped the decision of the features of the future production system in terms of oil and liquid processing capacity and adoption of some flexibility to make feasible the future development of marginal areas.
Exploration efforts offshore Brazil have been indicating important heavy-oil discoveries in deepwater reservoirs. The economic exploitation of these reservoirs presents technological and economic challenges that must be addressed. Therefore, the initial development plan must be defined through a detailed optimization study, considering economic indicators, oil recovery and risks 1, 2.
The development of Marlim Sul Field was planned in four modules: module 1 started in 2001 and has two production units producing 200,000 bopd. Module 2 will start the production through P-51 platform in 2008 and modules 3 and 4 are in development phase. These two last areas present special difficulties since they have oil viscosities greater than 20 cP at reservoir conditions. The introduction of new technologies could mean the solution for the feasibility of these projects.
Thus a research project was developed in the scope of Petrobras Offshore Heavy Oil Technological Program (PROPES) that comprised the following objectives: optimization of the drainage plan, taking into account the application of extended horizontal wells (around 800 m), evaluation of the use of high capacity plants for the processing of produced fluids and evaluation of the performance of artificial lift methods comparing the efficiency of gas lift and electrical submersible pumps. Studies related to the impact of the main N-S fault of the reservoir on the development plan, the consideration of uncertainties on rock and fluid properties and the analysis of the injectivity decline had also been performed.
This work focuses on the optimization of a development plan for Marlim Sul Field's third and fourth modules aiming at establishing a robust strategy encompassing all the geological and technological uncertainties.
Reservoir General Data
Marlim Sul Field is located in Campos Basin, distant approximately 120 km from north coast of Rio de Janeiro State, Brazil. It stands in water depths varying from 800m to 2600m in an area of 572 km2. Figure 1 depicts the field location.
This paper presents a simplified economical analysis of PETROBRAS' experience with the pilot project for polymer mobility control in the Carmópolis field, and an evaluation of the world and Brazilian current scenario of this technology.
The positive results of this pilot and the new world scenario of the oil industry, shown here, assure great potential of this technology, especially in a time marked by a rising oil prices and growing environmental and social conscience.
The pilot project was aimed firstly to evaluate the fit of the polymer technology to Carmopólis field, considering the particular characteristics of the field regarding rock heterogeneities, oil type, water salinity, temperature, pressure, etc. A second goal was to obtain know-how in all the project phases like lab tests, design and operation in field scale and, finally, technical and economical analysis as a function of the additional oil recovered and the direct investment. This economic analysis is a starting point for more comprehensive economical evaluations.
This economic evaluation closed the sequence and will be important to the possible future unfolds. This evaluation was done with a special criteria because of the operational typical difficulties of this kind of project. All the investment is justified by the fact of polymer injection to be, according the literature, the easiest application and one of the lowest cost of the incremental oil and besides, the onshore experience is the first step for the future offshore field application.
This experience demonstrated that the injection process of polymer for mobility control is efficient even for heterogeneous reservoirs as Carmópolis field, and still, in a sustainable way, in other words, with increase of the oil production and reduction of the use of the water and consequentially of the water produced, and of the costs and of the environmental problems associated to this water, in agreement with the new world partner-environmental conscience.
The first experience by PETROBRAS with polymer was in 1969, Carmópolis field, in the so called "Pusher?? project, with the polymer injection in the main block that lasted until 1972. The final evaluation of this Project, just done in 1989 by PETROBRAS Research Center (1), generating many controversies relative the success, or not, of the process. Many questions came up at the time, among them the correct design of the injected polymer slug, the product select, the surface equipment and the generated data accuracy.
Years later, despite of the controversial of this experience, the process attractively increased even more with the technologic advantages reached by polymers stimulating the PETROBRAS to invest in new polymer pilot, again in the Carmopólis field (September/1997).
The principle involved in the polymer project process to the mobility control is well-known; however its application in field is directly connected to the reservoir selection as well as polymer and slug specification (2-7). Another important point of this kind of project is the evaluation of the results (8) that for being a long step and involving a big group, if it is not done with criteria can harm all the experience.
Polymer flooding in oil reservoirs has been performed for several decades around the world. The polymers act basically increasing the viscosity of the injected water and reducing the porous media permeability, allowing for an increase in the vertical and areal swept efficiency of the water injection and, consequently, increasing the oil recovery.
The main subject of the pilot projects in PETROBRAS was to gain know how in the process, for a possible future expansion to other reservoirs and even to offshore fields. Because of the volume of information about this pilot experience, results have been presented in parts. A first previous paper presented the lab work on polymer and pilot area selection among with the field pilot design from that laboratory physical simulation. Then, a second paper was devoted to the technical evaluation, i.e., the reservoir response in terms of injectivity tests, characterization with tracers and analysis of the positive changes found on production profiles (7, 8). Finally, a simplified economical analysis of this experience is presented here as well as an evaluation of the current scenario of this technology.
This paper describes the implementation of a petroelastic model (PEM) based on Gassmann's equation to calculate seismic attributes into a commercial reservoir flow simulator. This implementation is the first step of a project to integrate time-lapse (4D) seismic attributes into an assisted history matching tool developed in a previous project.
The paper includes the description of the PEM and some implementation issues, such as the coupling of the model with the flow simulator with the purpose of using its basic calculated properties, discuss some user options (such as properties input through correlation or geoestatisticaly obtained maps) and the model variants and extensions (such as lithology influence and pressure effects). Three applications of this petroelastic model are shown: the first is a synthetic model based on outcrop data; the second is a 4D feasibility study for water injection monitoring in an offshore field; and the last one is a comparison between observed and calculated pressure impedances for an offshore field.
The resulting tool is applicable, for example, in 4D seismic feasibility studies, in seismic modeling for comparison with observed surveys and makes possible further implementations for incorporating the seismic data in assisted history matching.
The use of petroelastic attributes has several useful purposes1, such as feasibility of applying 4D seismic monitoring, optimize 4D seismic monitoring program and prepare more accurate production forecasts.
A possible workflow for applying 4D seismic in the monitoring of fluid flow in porous media follows the iterative steps2:
Steps 3 and 4 are unnecessarily cumbersome because most flow simulators do not calculate reservoir seismic attributes. As a result, information from the flow simulation Step 3 must be converted to a format suitable for analysis in the PEM Step 4.
In addition, errors may be introduced into the calculation of seismic attributes if fluid properties in the PEM do not match the corresponding fluid properties in the flow simulator, like using standard correlations of fluid properties.
These problems can be avoided if the PEM is incorporated into the flow simulator, eliminating the need of a third-party software to calculate the seismic attributes, so that it uses exactly the same fluid property model.
Fanchi1 shows the results for some reservoir management scenarios, applying successfully the petroelastic properties information calculated through an integrated flow simulator using the Gassmann's equation3, improving the reservoir management and monitoring processes.
Gosselin et al.4 also implemented an integrated flow simulator tool5 using the Gassmann's equation in a project to integrate 4D data into an assisted history matching process.
The ultimate aim of this project is to incorporate time-lapse seismic attributes into an assisted history match (AHM) tool, which combines efficient derivative calculation and robust optimization techniques, already developed in a previous project6 through an integrated reservoir flow simulator, facilitating a lot the viable use of this kind of data.
Two field pilot tests of immiscible water-alternating gas (WAG) injection are being conducted in Chihuido de la Sierra Negra, the largest oilfield in Argentina. Immiscible gas injection technology was selected because of its attractive incremental oil recovery potential for the two main reservoirs in this field. These are mature, waterflooded, undersaturated light oil sandstone reservoirs that are expected to reach a combined ultimate waterflood recovery factor of about 40 % OOIP. Scaled laboratory tests, pilot-scale simulation models, and pilot performance indicate that the immiscible WAG process can be expected to add between 3 and 8 % OOIP due to the contribution of several improved recovery mechanisms, namely oil swelling and viscosity reduction, and waterflood residual oil mobilization in three-phase flow. Another important mechanism that has been cited in immiscible WAG projects is improved volumetric sweep, either because of relative permeability effects or gravity segregation. The latter effect can be advantageous under particular circumstances, such as in clean formations with good vertical communication that may have undergone water underride during waterflood and may thus have unswept oil at the top of the reservoir.
This paper presents a status report on the preliminary evaluation of the performance of the field tests. Although we focus on oil production response and sweep efficiency estimation, a comprehensive view is presented including all the relevant production, facilities, environmental and reservoir engineering issues associated with the pilot tests.
The key to a successful evaluation of the process performance in the field is a quantitative assessment of the incremental oil production, volumetric sweep efficiency and compositional effects. These issues have proved to be more difficult than it was initially expected, due to the particular circumstances of the recent production history of the field and limitations in its routine measurement tools. However, careful data analysis, the introduction of unconventional measurement techniques and the use of numerical simulation have allowed to obtain performance indicators and to estimate the incremental production. These estimations are crucial for the decision analysis of project expansion to field scale, whose economics can be marginal due to high capital and operation expenses.
Chihuido de la Sierra Negra (ChSN) field is located in the Neuquén Basin in west-central Argentina, 200 km northwest of the city of Neuquén.
The field was discovered in 1968 and primary production began in 1979. Waterflooding started in 1993. Cumulative oil production is 82 Mm3 (517 million barrels) and cumulative water injection is 325 Mm3 (2 billion barrels).
The stratigraphic column of Chihuido de la Sierra Negra is shown in Figure 1. The 6-km thick column is composed of several sedimentary cycles including clastic and carbonatic deposits of both marine and continental origin, affected at different times of the basin evolution by flooding and transgression events and a temporal disconnection as a final result.
The producing reservoirs containing 60 % of the recoverable reserves are the Troncoso Inferior Member of the Huitrin formation, and the upper section of Agrio formation. (~ 1100 meters measured depth).
The quartz sandstones of the Avilé Member, deposited in aeolian dune fields, contain almost 30 % of the ChSN reserves (~ 1300 meters measured depth).
The depositional environments in the Troncoso Inferior Member include Aeolian dunes (5T and 4T intervals) and fluvial channels (3T and 2T). The middle portion of the productive column (Agrio superior) is formed by marine sandbars (3A, 2A, 1A and 0A). All the layers lack vertical communication between each other except 5T and 4T .
The Avilé sandstone has an originally saturated, 35°API oil and its main primary production mechanism was solution gas drive, with a minor influence of the expansion of a primary gas cap in the NE part of the field. Troncoso-Agrio reservoirs contained a slightly undersaturated, 33°API oil, produced also by solution gas drive. Both reservoir fluids are low viscosity and the rocks are water-wet, so response to waterflooding has been generally very good. Both reservoirs are currently with an important degree of undersaturation, which makes them attractive candidates for immiscible gas flooding.
In petroleum industry, scarce information is available at the time of adopt the exploitation strategy, and the expected production profiles comprise a high level of uncertainty. Depending on the range of the uncertainty variables, the best decision may be to collect more information by drilling more wells, performing a new seismic acquisition or making long term tests. But, sometimes, the best way to protect the project is to assume an uncertainty-proof development strategy. These ideas were applied to help decision in two real cases, in Marlim Sul field, Campos Basin, Brazil. In the first case, the main uncertainty source is the quality of the flow transmissibility between producers and injectors wells. If that communication is restricted, the production decline is more accentuated and the best strategy would be to place the injectors nearer the producers, although the displaced oil is reduced. In order to elect the best strategy, we have compared two different plans containing different positions of injector wells, applied to three different scenarios of flow transmissibility. In the second case, we have a channeled reservoir, with an extensive fault in the middle, the transmissibility along which is unknown. In a scenario of good communication, the best strategy is to position the injectors on one side and the producers on the other side of the fault. But in scenarios of restricted communication, the best scheme could be to place injectors and producers on both sides of the fault. To make the best decision, we have used different plans, applied to different scenarios. The results demonstrate that, in both cases, the alternate plan has not the higher net present value (NPV) in the moderate scenario, but presents the higher expected monetary value (EMV), having also a lesser sensitivity to the reservoir uncertainties, being more protected to the risk. In both cases the original plan has been abandoned and the alternative plan started being implemented.
The definition of the development project of an oil field is generally made with basis on insufficient information and under conditions of a great uncertainty as to the geologic parameters that characterize the fluid volumes and the flow properties. The adopted strategy is generally the one that produces the maximization of the fluids recovery, or the maximization of the economic parameters, when applied under the conditions regarding the most likely scenario. This scenario comprises the most representative image of the reservoir, with the most expected values of the properties related to the geometry and the flow of fluids in porous medium. After that, the analyses for characterization of uncertainty in the production curve, and also in the economic parameters, are carried out, with basis on the previously fixed project.
But this strategy may not be the most adequate, mainly if the uncertainties comprise a substantial range and if the application of the same strategy, under the conditions of the pessimistic scenario, reveals very serious consequences and very low economic results. An alternate strategy, less subject to these uncertainty sources, could be a more adequate option, even being economically less valuable and less appealing in the moderate scenario.
The purpose hereof is to present the application of a methodology of comparison and decision upon the best strategy for the recovery of oil, in scenarios of great uncertainty in the reservoir properties. The target field is situated in Campos Basin, Brazil, and two of its main development projects have been analyzed.
In the items hereafter some details on the field and its reservoirs, its main uncertainty sources and the strategies for the recovery or oil are presented. Following is it described the methodology of comparison of the strategies and, at last, the results of their application in two projects of the field.
Proposal of the problem: the field and its projects
Marlim Sul field is a turbiditic complex formed by channels, lobes, crevasse and spill deposits1. It is composed of fifteen reservoirs blocks of eocenic, oligocenic and miocenic ages, with excellent characteristics of porosity and permeability, and oil ranging from 15 to 25 API.
This paper describes an implementation of method to optimize the production in intelligent wells varying the wells inflow control valves settings using an optimization algorithm coupled to commercial flow simulators. The optimization is based on direct search methods. The optimization algorithm was coupled with two different commercial flow simulators and has been applied in two real Brazilian offshore fields to quantify the benefits of intelligent wells over a base case with conventional completion. The first field has three horizontal wells, two producers and one water injector, completed in two zones totalizing six inflow control devices. In this case, different scenarios have been analyzed varying the downhole valves type - on-off and multi-position. The results have shown that the intelligent wells scenarios increased the recovery factor and reduced the production and injection of water when compared with the base case (conventional completion). The second field has fifteen wells - nine producers with binary valves and six water injectors with six-position valves - producing and injecting in two or three zone totalizing 39 downhole valves to be optimized. In this case, the results have shown a significant increase of the expected cumulative oil production when compared with the base case.
The intelligent well technology provides the capability to remotely monitor and manage multiple production zones independently, reducing the cost of wells interventions, accelerating the production and reducing the injection and production of water. The ability to control multiple production zones comes from downhole inflow control valves. These devices may be binary (on-off behavior), or multi-position, choking the production zone with a discrete number of positions, or infinity variable position.
The benefits of the intelligent wells technology were shown in practical applications1-6 especially for multiple-zone producing commingled. During the operation with intelligent wells, one possible approach is to react when problems occur, for instance, choke the production zones with high water cut. Yeten et al.7 has called this approach as reactive control strategy. Another approach is to use the intelligent completions in conjunction with a predictive reservoir model. This model may be coupled with optimization algorithms to define production strategies that maximize the value of the field.
Some previous authors have studied the production optimization with intelligent wells. Brouwer et al.8, have presented a methodology that maximized sweep in a water flood study. The strategy was based on choking the segments with highest productivity index and redistributing the production in others segments. Brouwer et al.9, have applied the optimal control theory for production optimization. Yeten et al.7 have used a conjugate gradient optimization method coupled with a reservoir simulator to optimize the production with intelligent wells. They have proposed to divide the simulation into several steps of optimization. Ajayi et al.10 have applied an optimization process based on derivatives calculated as the change of the production rate of undesired reservoir fluid, water or gas, with the correspondent change in the desired fluid, oil or gas. The process corresponds to choke the zone with highest derivatives values in each time step. Naus et al.11 have proposed an optimization strategy with infinitely variable inflow control valves using a sequential linear programming to maximize production at a specific moment in time.
This paper presents an implementation of method to optimize the production in intelligent wells varying the wells inflow control valves settings using an optimization algorithm coupled to commercial flow simulators. The optimization is based on direct search methods. This kind of algorithm has some advantages in this case: the algorithm is based only in objective functions evaluations, this fact allows to consider the flow simulator as an external program like a "black box??; the algorithm permits to model binary and multi-position downhole valves, differently of gradient-based algorithms where is difficult to model problems with a finite number of discrete solutions; and the algorithm takes advantage in a grid computer environment, because the objective function evaluations can easily be done in parallel.
Ganga, Adriana de Oliveira (Petrobras S.A.) | Braga, Mario Sergio (Petrobras) | Silva, Edilon (Petrobras S.A.) | Braganca, Glaucia Holanda (Petrobras) | Maciel, Walter Becker (Petrobras) | D'Oliveira, Manoel (Petrobras S.A.)
Caratinga giant oil field is located in the central part of Campos Basin, Southeast of Brazil, in water depths around 1,000 meters. The total reserve is around 290 MM boe in these turbidite sandstones, 78% of which are within the lower Oligocene Reservoir (CRT100) and 22% are within Oligocene/Miocene and Eocene/Paleocene reservoirs. The CRT100 is a turbidite submarine fan of maximum thickness of 40 m, that was further cut by a NW-SE, Lower Oligocene submarine canyon, that have segmented the reservoir in two blocks: North Block and South Block. This canyon was further filled by the Oligocene MRL600/700 and the Oligocene/Miocene MRL330 sandstones. These canyon-filling sandstones constitute the Central Block. The development strategy for this field included a Pilot Phase in which three producer wells, one in each block, produced to a FPSO. The history match of this production data did not consider connectivity between the North and South Blocks of the CRT100 reservoir; although, seismic data have suggested possible reservoirs connection through the Central Block. Despite these features were represented in the 3D reservoir modeling, the transmissibility multipliers used kept these connections closed. The definitive production system, with 12 producers and 8 injection wells, started in February of 2005.
The extensive use of pressure down hole gauges and a dedicated reservoir team allowed the observation of very important new information about the reservoir hydraulic behavior. Among several other issues that have arisen, a good communication across the Canyon was confirmed, connecting the North and South Blocks. This effective hydraulic communication observed can be explained by the sand to sand juxtapositions between off-canyon and canyon-filling sandstones in some regions, whereas the low thickness
reservoirs, associated to geological faults, can justify the fluid flow behavior in other regions. These issues have been considered in the flow simulation model. The results are showing an increment on the total recoverable oil, since some portions of the canyon sandstones that used to have a low recovery volume, are now being swept by the water flooding.
Caratinga deep-water giant oil field is located on the southcentral part of Campos Basin, southeast of Brazil, in water depths from 850 to 1,350 meters (Fig. 1). The reservoir depths range from 2400 to 3200 m.
Fig. 1 - Caratinga Field location in Campos Basin
The total reserve is around 290 MM boe in these high quality siliciclastic turbidite reservoirs from the Tertiary, 78% of which are within the Lower Oligocene Reservoir (CRT100), and 22% are within Oligocene (MRL600/700), the Oligocene/Miocene (MRL330), and the Eocene/Paleocene (ENCOBR) reservoirs. The average gravity of the oil ranges from 20 to 29º API.
The CRT100, which is the main reservoir in the Caratinga Field, was cut in the Lower Oligocene, by a NW-SE submarine canyon that have carried part of the sands out of the Caratinga ring fence.