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.
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.
Traditionally, Non-Aqueous Fluids (NAF) have been used by a major operator to drill challenging wells in the Campos
Basin, Brazil. Significant advances in water based drilling fluid design in the recent years have allowed water-based drilling fluid performance to approach that of NAF. Exploration in the new frontiers and optimized development well projects in deepwater Brazil have required a different approach regarding drilling fluid design due long step outs, difficult well trajectory, and the possibility of drilling horizontal wells in one step, thus avoiding intermediate casing strings. Although NAF are an ideal candidate for those applications, environmental concerns and logistic demands are still an issue and alternatives should be considered.
HPWBM has been applied to replace NAF in some applications in deepwater and ultra deepwater (UDW) in the Campos Basin. This novel technology has been successfully applied to drill in UDW scenarios, reactive clays, dispersive shale, naturally micro fractured formation and horizontal wells. HPWBM characteristics are developed with: 1) A new generation of encapsulation polymers; 2) The use of amine chemistry to provide clay stability; 3) The application of novel sealing polymer for shale stability; and 4) Excellent mud lubricity characteristics.
The lessons learned, as supported by case histories and lab data have contributed to system modifications which have improved performance. This work has also identified attributes needed to complete a drilling fluid design for the difficult wells to be drilled in the new exploration and development areas. The evolution of HPWBM drilling fluid design will be discussed along with how decisions were made.
Today the industry is drilling more technically challenging wells difficult wells. Exploration and development operations
have expanded globally as the economics of exploration and production for oil and gas have improved with advancements in drilling technology. Advanced drilling operations such as deep shelf, extended reach, horizontal and deepwater are technically challenging, inherently risky and expensive. With consideration to reducing drilling problems such as torque and drag, stuck pipe, low rate of penetration and well bore stability; these wells are generally drilled with emulsion-based muds.
Nearly three quarters of the earth is ocean and a high prospect of hydrocarbon resources in addition to the other marine resources. That's why the industry is shifting from onshore drilling to offshore drilling. Published information indicates the presence of more than 20% of world's proven reserve in offshore geological structures. According to future production forecast of production reserves about 40-50% of future hydrocarbon recovery will be from offshore reserves. This is reflected by the increasing activity in the offshore environment with a gradual shift from shallow water drilling to deepwater drilling operations.
This scenario is particularly critical in the drilling exploration of offshore Brazil where the country faces the challenge of increasing oil production and reaching energy self-sufficiency within the next few years. Petrobras is well known for extended deepwater experience, however exploration in the new frontiers of ultra deep water face new challenges.
Risk is inherent to all phases of a petroleum field lifetime due to geological, economic and technological uncertainties, which are very significant on oil recovery in development phase, the focus of this work. The acquisition of additional information of uncertain attributes and flexibility during the development are key points to risk mitigation. The Value of Information (VoI) is used to quantify the benefits of new information, giving more accuracy to the project. The Value of Flexibility (VoF) measures the benefits of adding flexibility to the project considering different possible scenarios.
A new and reliable methodology has been proposed to quantify VoI and VoF based on the decision tree technique in order to combine the uncertain attributes. All reservoir models generated by the tree are submitted to parallel simulation and Geological Representative Models (GRM) are selected to represent geological uncertainties. The methodology includes the criteria used for selection of GRM, optimization of production strategies of each GRM considering the gathering of additional information and statistical treatment of the results.
The methodology has been applied in a decision-making process of a giant offshore petroleum field. The field has been developed by blocks due to its physical limitations and intrinsic characteristics and the high investment necessary to develop a giant field.
The contributions of this work are (1) to show the importance of VoI and VoF concepts in decision-making process in petroleum field development and the complexity of this type of decision, (2) to apply the proposed methodology in a giant offshore field modeled by parts, minimizing risks associated to the development of this type of field and (3) to evaluate the importance of the reservoir uncertainties in risk mitigation. An additional important contribution is to present the details of the use of reservoir simulation in the process, trying to obtain the best relationship between computation effort and reliability of the decision making process.
All phases of a petroleum field are influenced by uncertainties. The uncertainties are, usually, associated to reservoir geological characteristics or economic and technological parameters. The geological uncertainties influence the economic results of the project; however they can be mitigated by acquisition of additional information. The economic uncertainties depend on the political, financial and economic scenarios of the E&P industry. Although, economic parameters, such as the oil price, can highly influence the project evaluation, they can't be mitigated and have to be updated when they suffer significant variations. The technological parameters have influence mainly on production, investment and operational costs. The focus of this work is restricted to the reservoir geological uncertainties and consequently to flow characteristics.
Considering offshore petroleum fields, the cost of additional information is high due to high investment and low flexibility. In such cases, the decision analyses process needs to be probabilistic, mainly when the production strategy is defined. Probabilistic methodologies have to be simplified since the process is complex; there are many possible decisions and the computational cost of the reservoir simulation, the tool employed to evaluate alternatives, is high. Each possible scenario is associated to probabilities, which are quantified trough risk analysis.
The risk analysis can be applied to the various phases of the development process of a petroleum field (Santos and Schiozer, 2003). As decisions are different for each reservoir life phase, the methodologies and tools vary according to the phase. In exploration phase, the risk methodologies are well defined (Newendorp and Schuyler, 2000). In the transition from appraisal to the development phase, although the level of uncertainty is smaller, the importance of risk associated to the recovery factor may increase significantly. In this phase, various critical decisions, mainly related to the definition of the production strategy, have to be taken and the process complexity arises from high irreversible investments, large number of uncertainties, strong dependence of the results associated with the production strategy definition, and necessity of accurate reservoir behavior prediction (Schiozer et al., 2004).
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).
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 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.
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.
Castanhal is an onshore heavy oil field located in Sergipe-Alagoas basin northest of Brazil. It is a shallow unconsolidated sandstone reservoir. It has 75 wells where the average reservoir depth is 350m. The oil has high viscosity ranging from 1000 cp to 9000 cp and API gravity ranging from 10° to 16° API.
In early eighties, a small steam injection project was started in the field, but due to operational problems it was interrupted few years later. In that time the oil low prices make the field be practically abandoned: The production was carried on by very few wells without any fluid injection. In 2003, some successful experiences with frac pack and horizontal wells lead to a renewed interest in the field.
Geological and numerical studies have been accomplished and a permanent temperature monitoring technology was selected to improve the reservoir knowledge and validate the studies.
Among the monitoring technologies available in the market DTS (Distributed Temperature Sensing) was selected. It
allows a complete wellbore-temperature profile in few minutes if needed. In this case four observetion wells were equipped with an optical fiber placed along the entire length of the well.
This paper will present a steamflooding pilot in a nine spot, with four temperature observation wells completed with frac
pack to avoid sand production and DTS to improve the understanding of steam breakthrough in the producer wells
and the steam path in the injection well. The information support better decision making to increase steam injection
Castanhal field was discovered in June/1967 by 1-CL-1-SE well. It is located in Brazil and lies on north of the Sergipe-Alagoas basin and It is 50km far from Aracaju city (Figure 1). Its reservoirs are fine-grained sandstones and conglomerates from the Carmopolis Member of the Muribeca Formation, with high permo-porosity, saturated with biodegradeable oil, high viscosity ranging from 1,000 to 9,000 cp and API gravity ranging from 10o API to16oAPI. The oil in place (OIP) is about 178x106 bbl (december/2006).
Figure 1: Castanhal field map location.
The field produced oil by cyclic steam stimulation (CSS) and steamflooding during 1990 year and due to lower Brent prices and high operational costs related to sand face control the steam injection project was abandoned2. In 2001 this situation changed by a well succeded frac pack project with equipaments suited for steam injection. A new steamflooding project in a nine spot was started in june/2006 but now adding distributed temperature monitoring in four observation wells.
The geological interpretation of the well logs in about 73 wells drilled allowed, with confidence, to map four pay zones
MUR/CPS-1, 2, 3 e 4. The Figure 2 shows a well log from Castanhal field with its four zones.
Operationally Castanhal field is divided in four sandstone zones, CPS-1, CPS-2, CPS-3 and CPS-4 with different
geological characteristics. Zone CPS-2 has the best lateral continuity followed by zones CPS-3, CPS-1 and CPS-4, where this last one is more affected by the presence of shales.
Mixing of sea- and production waters during waterflooding of offshore oil reservoirs results in reaction of barium and sulphate ions causing precipitation of barium sulphate with consequent rock permeability decrease and well productivity decline. The reliable productivity decline prediction is based on mathematical modelling with well-known model coefficients. The sulphate scaling system contains two governing parameters: the kinetics coefficient characterising the velocity of chemical reaction and the formation damage coefficient showing how the permeability decreases due to salt precipitation.
Previous works have derived analytical-model-based method for determination of both coefficients from breakthrough concentration and pressure drop during laboratory coreflood on quasi steady state commingled flow of injected and formation waters. The current study extends the method and derives formulae for calculation of two scale damage coefficients from just pressure drop measurements during two corefloods with two different ratios "formation water : seawater??.
Data from series of three corefloods on commingled injection with three different "formation water : seawater?? ratios, were treated. Equality of scaling damage parameters as obtained from three different floods in similar artificial cores validates the method proposed.
In deepwater offshore operations where seawater injection is a common development practice, barium, calcium, and strontium sulphate scale deposition is a serious concern. Barium sulphate and related scale occurrence is considered a serious potential problem that causes formation damage near the production-well zone1-5. The major cause of sulphate scaling is the chemical incompatibility between the injected seawater, which is high in sulphate ions, and the formation water, which originally contains high concentrations of barium, calcium, and/or strontium ions6-9.
A reliable model capable of predicting such scaling problems may be helpful in planning a waterflood scheme. It may also aid in selection of an effective scale prevention technique through the prediction of scaling tendency, type, and potential severity.
A reliable predictive model must use well-known values of the model coefficients.
The mathematical model for sulphate scaling contains two phenomenological parameters: the kinetics coefficient from active mass low of chemical reaction showing how fast the reaction and precipitation occurs, and the formation damage coefficient reflecting the permeability decrease due to sulphate salt deposit10-15.
Both coefficients are phenomenological parameters depending on rock surface mineralogy, pore space structure, temperature and brine ionic strength. Therefore, they cannot be calculated theoretically for natural reservoirs and must be determined from laboratory corefloods.
Reagent and deposition concentration profiles during reactive flows are non-uniform. So, the sulphate damage parameters cannot be directly calculated from laboratory measurements. They must be determined from laboratory coreflood data using solutions of inverse problems.
The quasi steady state commingled corefloods by sea- and formation waters were performed by numerous authors16-19.
The kinetics coefficient can be calculated from breakthrough concentration in quasi steady state coreflood with commingled injection of sea- and formation waters. Then the formation damage coefficient can be determined from pressure drop increase during flooding20,21.
The pressure drop measurements are simple and robust while breakthrough concentration determination is a cumbersome laboratory procedure. Therefore, often concentration data are unavailable17. Availability of the method for characterisation of scaling damage system from pressure measurements would simplify the laboratory procedure on sulphate scaling studies. This is the subject of the current paper.
Based on analytical model for commingled coreflood by sea- and formation waters, the current paper develops a method to determine two scaling damage parameters from pressure measurements during two floods with different "formation water : seawater?? ratios.