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.
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.
In this paper, we will describe techniques used to overcome the problems faced on the hydraulic fracturing jobs during the oil-to-gas conversion campaign in the Pilar field, Brazil.
The increasing demand for clean-burning natural gas in the Northeast of Brazil is fueled by the region`s industrial growth over the recent years, and represents the main drive for the oil-to-gas conversion campaign witnessed in the wells previously producing at marginal oil rates from the Coqueiro Seco formation in the Pilar field. These old wells are now producing gas from the 3000 meters deep Penedo sandstone formations. One of the main steps to meet the goals for natural gas output in the Pilar field was the hydraulic fracturing campaign in the deep Penedo formation. The treatment design and execution process to create these fractures was quite distinct from the normal jobs aiming at increasing the oil productivity in wells producing from the shallow Coqueiro Seco formation.
The Barra de Itiúba gas-bearing formation in the Furado, São Miguel dos Campos and Cidade de São Miguel dos Campos fields was also included, to a lesser extent, in the stimulation campaign aiming at the increase in natural gas production.
This paper describes the completion strategy for the old wells converted from oil to gas producers, highlighting the problems faced and overcome during the hydraulic fracturing campaign. In deviated wells crossing the deep Penedo reservoir, the risk of multiple fractures and influence of tortuosity have been diminished through corrective techniques, unique for each one of the existing wells. In the early hydraulic fracture treatments performed in the Pilar field, premature screen-outs were commonplace, disencouraging the use of the technique. The need to produce gas brought new ideas to the battlefield, and their implementation led to results beyond expectations.
The intense investiment to increase production of natural gas in the Alagoas, and its export through an expansion of the domestic natural gas transport network in the Northeast of Brazil, has the objective to keep up with the rapid growth in the regional gas consumption, due to an increase in the natural gas fired electricity generating capacity. Natural gas demand in Brazil, 1600 million scf/day in 2006, is expected to reach 4300 million scf/day by 2010, the direct result of investments in the sector estimated in US$ 22 billion.
The natural gas processing plant in Pilar was built to develop the compressed natural gas market for automotive, residential and commercial use in Alagoas, and to export gas through the Pilar-Cabo pipeline. Before its construction, all natural gas produced in Pilar and its neighboring fields was exported for processing and pumped back in the form of liquified petroleum gas. Seventy million scf/day of natural gas are processed in the Pilar plant, producing liquified petroleum gas, industrial gas and gasoline.
Given the increased demand for natural gas in the region, the gas-bearing formations in the Pilar area became attractive targets. Hydraulic fracturing played a major role in converting old oil wells producing at marginal rates from the shallow Coqueiro Seco reservoirs into good gas producers.
The Pilar Field
The Pilar, São Miguel dos Campos, Cidade de São Miguel dos Campos and Furado onshore gas and oil fields are located in the state of Alagoas, in the Sergipe-Alagoas Basin, in the Northeast of Brazil (Figure 1).
The Pilar field, discovered in 1981, is located near the city of Pilar (Figure 2). The Pilar field is characterized by intense compartmentalization produced by deltaic sedimentation that resulted in a stacked package of more than one hundred pay intervals, and by the extensional tectonics that produced a large number of fault blocks (Figure 3). The deposition occurred during the rift phase of the geologic evolution of the Sergipe-Alagoas Basin, in the Lower Cretaceous.
Intercalations of deltaic sandstones and shales compose the Coqueiro Seco formation, found at depths ranging from 500 to 2500 meters. These oil-producing sandstones have porosity of 20% and permeability of 100 mD.
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.
Rodrigues, Valdo Ferreira (Petroleos Brasileiro S.A.) | Neumann, Luis Fernando (Petrobras S.A.) | Torres, Daniel Santos (Halliburton Energy Services Group) | Guimaraes De Carvalho, Cesar Roberto (Schlumberger) | Torres, Ricardo Sadovski (BJ Services Do Brasil Ltda.)
This paper presents a brief review of the available techniques in the oil and gas industry to complete and stimulate horizontal wells, with emphasis on low permeability carbonates. These techniques can also be applied in non-conventional reservoirs, particularly in tight formations. The paper starts by reviewing the lessons learned in some chalk fields in the North Sea (Dan, Halfdan, South Arne, Valhall and Eldfisk) and in a few pilot projects offshore Brazil (Congro and Enchova). Based on these lessons learned and in the broad literature, the paper devises some considerations on the methodology to select completion and stimulation techniques for horizontal wells. Cased and cemented horizontal wells, in addition to open hole and perforated/slotted liners wells are addressed. The macro aspects of field/area management are stressed as the completion and stimulation drivers. The key parameters for designing, implementing and evaluating horizontal completion and stimulation are presented, emphasizing the most common failures and the controversial aspects. The paper presents a summary of mature field and new scenarios that are candidate to horizontal completion and stimulation in Brazil and other Latin America countries. Then it makes a few comments on the resources available in Latin America to face the mentioned opportunities and related challenges. It is supposed that this brief review will be useful for the low permeability scenarios in Latin America and worldwide.
This paper presents a brief review of the available techniques in the industry to complete and stimulate horizontal wells, with emphasis on low permeability carbonates. The emphasis on low permeability carbonates in this work is justified by the renewed importance of this scenario in Brazil and other Latin America countries. Although it does not focus on nonconventional reservoirs, such as tight gas, it is related to them as stimulated horizontal completions have been used on their development. This paper focuses fracturing stimulations, also making a few references to matrix stimulation. It also assumes that a horizontal well has already been justified and what is being discussed is its completion and stimulation. The paper starts by reviewing the lessons learned in some chalk fields in the North Sea (Dan, Halfdan, South Arne, Valhall and Eldfisk) and in a few pilot projects offshore Brazil (Congro and Enchova). Then it devises some thought on the methodology used to select completion and stimulation techniques for horizontal wells. It address cased and cemented horizontal wells, in addition to open hole and perforated/slotted liners completions. The key parameters for designing, applying and evaluating horizontal completion and stimulation are presented, underlining the most common failures and the controversial aspects.
Completion and Stimulation of North Sea Low-Permeability Carbonates
The North Sea low permeability chalks are taken here as a reference due to the outstanding technological evolution verified there in the last decades. Amongst more than ten fields producing from these reservoirs in the North Sea this paper focuses on the Dan, Halfdan, South Arne, Valhall and Eldfisk fields. The main characteristics of these fields are: shallow waters (43 to 69 m), dry completion, high volumes of OOIP (1.6 to 2.9 billions barrel), low permeability carbonates (0.2 md to 10 md) with microfractures in the central areas (10 md to 120 md), high porosities (up to 48%), soft to very soft chalks, small to medium net pays (15 m to 65 m), high oil saturation (up to 97%), and light oils ( about 36o API).
What most distinguishes these fields is their over-pressured soft chalks which are subjected to a high degree of compaction under pore pressure depletion, resulting in loss of drilling fluids, rapid production decline, well failures and seafloor subsidence. On the other hand the positive effects of rock compaction as a reservoir drive energy, outweigh by far the negative ones. The recovery factor under primary recovery can be as high as 30%. In general the North Sea chalks experienced an evolution from vertical/directional wells stimulated with acid treatments to multiple fractured horizontal wells.
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.
The objective of this study is to determine the minimal well length required to achieve a desired productivity index (PI). It considers the main uncertainties associated to fluids and reservoir properties (vertical and horizontal permeability, net oil thickness and oil viscosity). Monte Carlo analysis is used to consider possible combinations of these parameters and generate probabilistic results.
This study was developed for a heavy oil reservoir. Oil of 15ºAPI or less and viscosities up to 150 cp are expected. The results obtained can be used in the planning phase. The reservoir properties are evaluated initially by a pilot well; afterwards they are estimated along the horizontal length. During the horizontal well drilling, this model can be easily updated. A theoretical model presented in JOSHI (1988) is used to calculate the horizontal well PI. It considers the influence of anisotropy in permeability.
This work is divided in two parts. Initially, a sensibility analysis is performed regarding each uncertainty parameter separately. This first stage is necessary to evaluate the most impacting parameters. The procedure was applied for several well lengths. In a second phase, Monte Carlo analysis is applied, considering simultaneously the uncertainties associated to these parameters. This analysis provided three levels for well PI: pessimistic, most probable and optimistic curves as a function of well length.
This methodology is flexible and, for this practical case, it was implemented through a spreadsheet that comprised the required probability density functions and the Monte Carlo analysis. It can be implemented with other development programs that suit the reservoir engineer. The results obtained can improve the estimates for the performance of the wells and can be used to design adequate horizontal wells for field development.
This paper presents the key aspects of the study of determining the minimal well length in order to provide a desired productivity index (PI) as well as the strategy adopted in order to overcome the main reservoir uncertainties.
There are several uncertainties involved in the prediction of a well productivity index. These uncertainties are present in rock properties, like net oil thickness and absolute permeabilities, in fluid properties, like viscosity, and properties depending on both, like relative permeabilities. In a horizontal well, vertical permeability is also an important factor to estimate the productivity.
In order to model the reservoir behavior, a good estimate of well PI is necessary. Depending on its value, the initial oil rate can be considerably different. This effect is more important when the PI values are low, and it is the case of heavy oil fields.
For this case, due to the challenging field environment - low API and viscous oil, and reservoir thickness ranging from 15 to 35 meters - the use of emerging technologies such as long horizontal wells and thermal insulated flow lines is required.
The field is located at water depths ranging from 800 m to 2000 m, with small sediment cover of only 500 m in the studied area. The reservoir is Miocene sandstone with high porosity and permeability. The fluid distribution in the reservoir is quite complex.
The field development comprises 17 production and 15 injection horizontal wells and the oil production is around 27.000 m3/d (170.000 bpd), with 14 production wells operating.
In a horizontal well, several aspects must be considered to calculate the productivity. A methodology was presented by JOSHI (1988), considering several aspects involved in the problem, like well eccentricity and anisotropy influence in permeability. In the present study, skin factor and horizontal well eccentricity were not considered.
Although there are several methods for predicting horizontal well productivity index (GIGER, 1983, KARCHER et al., 1986 etc.), JOSHI equation was adopted since its results represent better the values found in other wells in the same field.
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.
In mature fields, operators are often seeking ways to increase the hydrocarbon recovery, with the help of reputable service companies. Well stimulation continues to be, by far, the preferred method of achieving such goal. Operators and service companies are continually screening out technologies which will deliver the highest benefit/cost ratio for a particular stimulation well treatment, maintaining focus on operational and health, safety and environment excellencies .
This paper addresses the rebirth of a past hydraulic fracturing technique, born in the 50's, and how it is being successfully applied on onshore mature fields in Brazil: batch fracturing. It is effective due to several technological advancements on proppant density, becoming lighter than conventional frac sand and yet with sufficient mechanical properties to withstand bottom-hole environments. Batch fracturing is now contributing to equally efficient, and more economical well stimulation treatments, providing good economical returns to operating companies.
Batch-Fracturing had limited success in the past. This was due to the available frac fluid and proppant technologies at that time. It is desirable that proppants have low settling when carried by a fracturing fluid, from the time they are added into such fluid, until the end of the pumping process. Batch fracturing applications are on the rise, due to the new families of ultra lightweight proppants, with specific gravities ranging from 1.05 to 1.75. In batch fracturing, the proppant is added to the carrier fluid prepared in standard oilfield mixing tanks,
eliminating the need of specialized mixing equipment such as blenders. Less sophisticated equipment on location implies in lower operational and logistical costs. The carrier fluid ("frac fluid??) does not need to yield high levels of viscosity, and, by consequence, does not have a high load of chemicals (gelling agents, cross-linkers, related breakers…). With batch fracs it is possible to perform common but effective types of fracturing treatments, such as "skin-by-pass?? (a fracture that by-passes the damaged zone), and "partial mono layer' fracturing, both exemplified in this paper, through case histories.
Today, most of the producing oil and gas fields are considered mature. Although continually being redefined, a field is considered mature when its current level of hydrocarbon production has passed its past production peak. Associated with the reservoir's production depletion, there are other hydrocarbon recovery issues inducing operators to continually seek ways to overcome these natural effects. They look, with their subcontracted service companies, for cost effective techniques and technologies able to increase production and
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.