Coste, J.-F. (Total Fina Elf) | Valois, J.-P. (Total Fina Elf) | Mouret, Cl. (Total Fina Elf) | Guittard, M. (Total Fina Elf) | Baleix, J.-M. (Total Fina Elf) | Larrouquet, F. (Total Fina Elf) | Mastin, E. (Total Fina Elf) | Daniel, O. (Total Fina Elf)
Mature fields have a long production history file, and many other large data sets (static data, pressure, and so on). The challenge is often to select the most promising object (a field in a block, a reservoir in a multilayered field, or an area in a wide field). We present a global approach to solve this difficulty, that uses the concepts of Data Mining. It involves Sampling (gather the data, validate, and select the appropriate level of detail), Exploration (using a large set of graphical tools), Data Management (for production data, extracting production indicators), Modelisation (using for instance the hyperbolic oil production decline equation), and Aid to final decision.
All along, graphical tools and multivariate statistical analysis are widely used and must be carefully designed. The whole of the approach requires a good geological and reservoir experience and a Reservoir and Geological Synthesis (RGS). Three field cases illustrate this fast track approach.
Oil and gas companies have to face an ever increasing offer of fields for farm in, that have a long production history, because many fields were started in the 1960's, 80's and because the international market is more widely open. Companies portfolios include fields with a large number of wells -- several hundreds or more -- and several decades of production history. For these mature fields, extracting the most -- or the best -- of existing reserves is a must, for both the Companies and the countries with reserves. The remaining potential of these fields may be rather large. In some cases, it is necessary to solve all production-related difficulties that became apparent meanwhile the field was under production : insufficiently known heterogeneities, production mechanisms implemented with an unclear impact on production development, as for instance an insufficient reservoir pressure response to injection. In other cases, fields were developed with classical scenarios of natural depletion or water injection. The implementation of new techniques of EOR, or IOR, can sharply increase remaining reserves.
Some papers have already been published about analytical evaluation methods for mature fields, that are not based on reservoir numerical simulations (Ref. 1 to 4). Recently, Albertoni and Lake (Ref. 5) have released a method to investigate well connections, on the basis of production rate fluctuations in five spot waterflood patterns. Multivariate linear regression method were applied.
We now present a global methodology, based on our "Welfare" integrated software. Many types of data can be taken into account and subjected to statistical processing.
Presentation of the method
A noticeable part of today reservoir re-engineering activity is related, either to the selection of most promising zones, if one reservoir is concerned, or to most promising layers, when a multi-reservoir field is investigated. The challenge may even be to perform a fast track selection of a few fields among many. Each field has its own geological characteristics and its own development patterns and presents related difficulties in terms of performance, sectorisation, response to production mechanisms or location of untapped reserves.
Petroleum engineers are facing a challenge which is comparable with those encountered in marketing, e.g. in the management of the relationship with the customer. Investing in the relation with a long-time customer is cheaper than acquiring new clients, and it can provide a lot of profit (Ref. 6). The most appropriate approach needs the personalisation of the relationship. So, the challenge is to extract the relevant information, concerning a small, but promising, part of customers in a market. Data Mining techniques are now currently used for this (Ref. 7).
Many of the once prolific North Sea reservoirs have been reduced to mature assets, with a majority having reserves down to a fraction of their initial value. A significant number of isolated pockets of hydrocarbon bearing sands, however, remain available for production. The advantage of pursuing such bypassed assets is the availability of an existing infrastructure to support any incremental production. The biggest challenge when considering production enhancement initiatives is the marginal nature of the associated economics combined with project risk. In addition, marginal and mature assets seldom generate required engineering firepower to solve complex problems. Lack of investment results in decreased production and downward spiral that only can result in often-premature field abandonment.
This paper describes how Marathon identified a requirement for an alternative commercial arrangement and together with a selected service company, built an effective team that rejuvenated a dwindling gas asset. An inter-disciplinary study was initially undertaken to quantify and manage economical risk associated with this project. Previous attempts at rejuvenating production were revisited to assess reasons for their ineffectiveness, or success. An alternative commercial model was then applied to help overcome the marginal nature of the economics. A data acquisition campaign was subsequently undertaken to determine the optimum intervention alternatives. Successful execution of the intervention activities has delivered a two-fold increase to total field production.
Several recently introduced technologies were employed during the course of the project. The project also spawned multiple field practices. Their conceptualization, field implementation and long-term effects on production are also described.
Contributions. This paper will present the application and results from several initiatives, including:
Descriptions of an alternative commercial model, where the operator and service company mutually participate in the project risk, and its rewards.
Implementation of the lift-log procedure, a single trip, combined, coiled tubing N
Utilization of scale-inhibitor impregnated proppant. This specialized proppant prevents loss of conductivity due to scale deposition within a fracture.
Technical, commercial and operational best practices for use with mature field rehabilitation projects.
The Beinn field was the first high pressure gas condensate development in the North Sea. The field is located in North Sea Block 16/7a and lies structurally below the North Brae field at depths of 13,700 to 14,700 ft TVDss (Figure 1). The reservoir is composed of shallow marine sandstones of the Middle Jurassic Hugin Formation with four distinct hydrocarbon bearing reservoir intervals. Reservoir quality is moderate with porosity averaging 12% and permeability ranges of between 2 and 100 millidarcies (average field perm is 74 md). Due to the low permeability in some of the reservoir layers, hydraulic fracture stimulation was attempted on three of the four completions. The first treatment (B20) was considered to be very successful and the others showed marginal improvements. The Hugin Formation fluid is a gas condensate with initial yield of 137 bbls/MMscf. Due to the high initial pressure (11,347 psi at datum) and the low dew point (6,938 psi), the reservoir was produced under depletion rather than gas cycling. First production from the field was achieved in 1992 and drilling of the four well development was completed in 1995.
Most data collected by operators in the North Sea is moved from the contractor to the operator, copied for use within the operator and then copied again to partners. Some data is stored to meet regulatory requirements and/or delivered to the regulator. The consequence of this multifaceted life of the data is the same data is available in many locations with an ever-increasing probability of alteration and corruption as more and more people use it. The net result is a significant amount of avoidable time, and money, spent on copying and data quality control as the same data moves to and fro.
The estimated savings available in the UKCS from managing data ONCE! are of the order of £ 1.5 billion per annum, or about US$1 per barrel. Realizing these savings would enable vital increased recovery in the North Sea, and beyond.
Managing data ONCE! employs a set of principles, which, when applied will result in the realisation of these practical savings. The principles are:
One time data management
New ways of working
Consistent and correct data
Economic and efficient
Usage of this principle set achieves value delivery to the operator, partners, and industry as a whole.
One time data management results in a New way of working that delivers Consistent and correct data. The Economic efficiencies achieved through reliable data being managed once, with secure storage and access availability, translate into significant cost savings!
Just as poor management of data can have a significant effect on the bottom line profitability. Placing a cost on managing data ONCE! and employing best practice data management is a key economic advantage.
Over the past few years the hydrocarbon exploration and production industry has made some significant advances in the management of the data and information, which is used on a day-to-day basis in decision making. Most of these advances have been in the area of geoscientific data rather than the petroleum engineering/production data area. The lessons learnt from the changes required in this area are applicable to the engineering environment.
This paper looks at a number of case studies where information management practice has been investigated. The principles of ONCE! are then explained and some examples of the economics are outlined.
Whilst the principles of ONCE! can be applied using any technology (or lack of it) it is the most recent advances which offer more hope of maintaining these principles. However the technology alone will not solve the problems encountered. It requires a concerted effort by people to change their habits.
One long-term driver for the changing of habits is the demographic shift in the population employed in the E&P industry. Many graphs have been published to illustrate the problem. Fig 1 is one such example. The problem for the majority of managers in the industry is that the time scale is too long, most are judged via quarterly or at best annual performance contracts. A problem, which sits a few years out is off the radar screen of the majority!
The normal reaction of those who do look at these figures is that we, the E&P industry, need to recruit more young people and retain the services of the older, experienced people longer. If the principles of ONCE! are applied the numbers of young people currently joining the industry may be sufficient and those older employees who wish to retire will be able to do so!
One of the major issues in processing permanent downhole gauge (PDG) data is that there exist too many transients over a reasonable time period, say six months. A formula has been proposed to predict the transients that may be detected or missed. Reasonable prediction has been achieved via the formula.
Noise usually exists in data recorded by permanent downhole gauges. Denoising is thus one of the most important steps in PDG data processing. In order to denoise the data, data noise level must be estimated beforehand. Unfortunately, the data noise level is typically case-dependent, therefore, it is impossible to identify a universal value for the level that may be used for all the application scenarios.
One appropriate approach to estimate the noise level is to first best fit the data, subtract predicted pressure response from recorded values, and then calculate the noise level based on the difference1. We proposed to apply nonlinear regression via Polytope method2 for best-fitting PDG data to determine the noise level. It is found that the new approach is superior to the least square error (LSE) linear regression as used by Khong1, because the bottomhole wellbore pressure response in a well should be treated as a nonlinear function of time over majority of the well production/injection/shut-in period. Unless very small range of the data (say 2 hours) is considered, linear pressure response with time is not anticipated. Furthermore, with nonlinear regression through the Polytope approach, there is no strong restriction in data quantity and data density, hence, automatic detection of data noise level can be implemented.
Other improvements to the PDG data processing procedure, such as trend analysis, steamlinization of data preprocessing, step outlier removal, and so on, will also be discussed.
More and more permanent downhole gauges (PDG) have been installed in oil or gas wells all over the world to monitor the well condition in real time. Continuous measurement of pressure enables engineers to observe ongoing changes in the well and make operating adjustments accordingly to enhance oil and gas recovery. The installation of permanent downhole pressure gauges has proven to be cost-efficient for well and reservoir monitoring, not to mention significant saving of well-testing cost and the additional reservoir information obtained from the processing of PDG data. Nowadays, PDGs can record not only pressure and temperature, but also total flow rate, phase flow rate, phase fraction, resistivity, and so on. PDG is playing a more and more important role in improving reservoir and well management.
Pressure has always been acting as the most useful type of data that may be used for obtaining reservoir parameters, monitoring reservoir conditions, developing recovery schemes, and forecasting future well and reservoir performance. Reservoir properties can be inferred by matching the pressure response to reservoir model(s) since the alteration of production conditions, such as well shut-in, production or injection rate increase or decrease, skin change, formation compaction, etc, are reflecting in the changes of wellbore or reservoir pressure. The inferred fluid/reservoir parameters and reservoir model(s) can then be used for future reservoir management.
Compared with pressure data from conventional pressure transient tests, long-term pressure data from permanent downhole gauges include more valuable information about a reservoir. This type of long-term surveillance provides the opportunity to feature the reservoir information in four dimensions rather than obtaining a glimpse or snapshot in time3.
In September 2000 the Forties Field celebrated 25 years of production. Recovery up to this point is approximately 60% of the original oil in place. The field contains undersaturated oil and is being developed under waterflood. A screening study of Increased Oil Recovery (IOR) options highlighted CO2 injection as technically feasible, suggesting an additional recovery of in the range 5-10% of the initial oil in place (STOIIP), subject to further work on the investment economics of the project and corporate sanction. This paper describes the study of the CO2 injection scheme with a focus on the reservoir simulation workflow.
Various techniques for evaluating the full field benefits of IOR schemes can be used including the Todd and Longstaff approach1 or a coarsely gridded conventional compositional reservoir simulation model. The evaluation presented in this paper builds upon a technique that incorporates detailed conventional simulation results into a full field streamline front-tracking simulation. This method was originally developed by Arco and has been successfully applied in several Alaskan oil fields2.
The technique captures the complex physics of the IOR process through fine scale, 3D, compositional, finite difference simulations of ‘type' sections of the reservoir (the original method used 2D simulations). Results from these simulations are then used to calibrate ‘recovery' curves that capture characteristics of oil mobilisation and returned solvent volumes as a function of gas injected. The calibrated curves representing gas injection response are then applied as tracers using streamline front tracking simulation to scale up to full field response.
The Forties field, discovered in 1970, is located 170 km NE of Aberdeen, UK, in blocks 21/10 and 22/6a. The field is a relatively simple four-way dip structure. The oil is trapped in a stacked turbidite sandstone sequence. The field consists of four main channel sand complexes: the Main, Alpha/Bravo, Echo and Charlie. The Charlie sand is isolated from the other channels. On either side of the Charlie Channel is an area of more sheet-like sands referred to as the Charlie wing.
Forties is currently producing around 60 mstb/d, approximately 10% of its plateau production rate. The field is being produced under waterflood. STOIIP at discovery was 4.2 billion bbls and remaining reserves are currently some 137 mmbbls of oil, giving a recovery factor of approximately 61%.
The Forties IOR screening project is one of a group of such projects forming an integrated approach to Forties depletion, to reduce costs and improve production. Together they have the potential to improve the recovery factor by 10% of STOIIP. We believe that gas displacement IOR can contribute to more than half of this.
The study of the Forties field IOR response to CO2 injection requires the use of reservoir simulation: CO2 injection results in a highly complex multi-contact miscible displacement process. Presently the most complete capture of the complex physical behaviour of the CO2 injection process is achieved by using a Compositional Finite Difference Simulator (CFDS) with small-sized grid blocks to enable the required multiple gas and oil contacts to be modelled. A full field large grid block model could be used to determine the IOR benefit but, without the necessary multiple oil and gas contacts between injectors and producers, the response of the model will probably be inaccurate.
An innovative completion method was recently used to complete a well in the Skua oil field in the central area of the North Sea. The Skua field is part of the ETAP (Eastern Trough Area Project) and is borderline high-pressure/high-temperature (HP/HT) with a reservoir pressure of 9,350 psi and a reservoir temperature of 307 (F. The initial field development plan was to have one subsea well with a horizontal reservoir section of 2,000 ft to drain the prospect. Production would be tied back to a central processing platform.
The completion design for this well had to address several challenges.
What method could be selected for sand control in the long horizontal section
. What equipment would maintain integrity in near HP/HT well conditions
What configuration would allow the completion to be run underbalanced without completion isolation devices.
Several completion options were reviewed. A new gun- deployment system based on production packer technology was chosen because it appeared to offer the best option for meeting all the well requirements. The system would also allow the tubing-conveyed perforating (TCP) guns to be recovered if they failed to fire or malfunction.
Orientated perforating guns were used to mitigate sand production. The gun system was deployed from a novel polished bore receptacle (PBR) and permanent packer system that allowed for retrieval of the guns should they fail to fire or malfunction after the packer had been set. The polished bore receptacle and hydraulically set permanent packer were designed with the guns hung off the seal assembly of the polished bore receptacle and the tailpipe run through the permanent packer to the TCP guns.
A significant feature of the hydraulically set packer-TCP gun deployment system is that it allows contingencies for recovery of the completion and TCP guns from the well in the event of a total or partial perforation misfire. This was a necessary requirement in view of the fact that a long perforation gun string was to be deployed in a high-temperature reservoir where there would be an increased risk of gun failure due to the ambient reservoir conditions.
The Skua well was completed with a fully cemented liner. The completion and TCP guns were run, and the well was successfully completed and perforated underbalanced (without an isolation device) in a single trip.
This paper will describe the selection method as well as the development, testing, and implementation of a new TCP permanent production packer system.
The Skua field is operated by Shell U.K. Exploration and Production on behalf of Shell and Exxon Mobil and situated in the Central North Sea block 22/24a (Fig 1). The subsea development well, Skua S1, was successfully drilled and completed with first oil produced in October of 2001. The well was designed for an initial production rate of 25,000 BOPD. The well is a subsea tieback exporting oil production via flowline to the BP operated central processing facility. (See Fig. 2)
Skua is a near-HP/HT field with initial reservoir pressure of 9,350 psi and 307° F bottomhole temperature (Table 1). The Skua reservoir fluid is a highly pressured, undersaturated light oil of 42 degrees API gravity. The Skagerrak reservoir is located at a depth of 11,735 ft TVDSS, 13,170 ft along hole below drill floor (AHBDF) and is accessed with a 2000 ft horizontal liner section to maximize production from compartmentalized zones.
There are over 300 undeveloped discoveries on the UKCS, estimated to contain aggregate reserves of more than six billion barrels of oil equivalent. A comprehensive survey has identified that low well deliverability is a primary challenge to development of this resource.
Following literature reviews, a series of information-gathering meetings was conducted with both oil companies and service providers. Thirty-five undeveloped discoveries were examined in detail and the knowledge gained was used to design an interactive workshop. This paper summarises information from fourteen companies and identifies barriers associated with low deliverability reservoirs and corresponding solutions. The reserves associated with specific barriers and potential solutions are highlighted.
Undeveloped discoveries with a well deliverability barrier are typically low permeability, thin- or inter-bedded and with uncertain reservoir connectivity. The technical barriers are challenging, but many solutions exist to manage the risks and uncertainties. For example, better-targeted, long and/or multi-lateral well-bores, hydraulic fracturing, under-balanced drilling and non-damaging drilling and completion fluids all have potential to raise deliveability.
In other cases, solutions are being developed, such as improvements in modeling structurally complex reservoirs and advances in the areas of seismic resolution and prediction of reservoir performance from seismic data.
Non-technical solutions also have an important part to play. An example is where companies form an alliance to strengthen their technical capability and generate a sufficient resource target in an area such as under-balanced drilling. The study found that the drive towards low cost can often be at the expense of adding value. Service providers frequently found that even within the same company, buyers and users have different objectives. Buyers are driven by ‘cost', whereas users should be driven by ‘value'. There needs to be a shift towards value-based procurement practices, with a re-appraisal of company objectives and internal performance measures. Similarly, more effective contracts are needed which recognise the impact of risk.
The stage is set for a new wave of activity on UKCS developed fields and undeveloped discoveries and a series of recommendations is made to help facilitate their development.
The large portfolio of undeveloped UKCS discoveries is a significant target for reserve additions and new investment. Various studies have indicated that there are over 300 undeveloped discoveries, containing aggregate reserves in excess of six billion barrels of oil equivalent (BBOE). The distribution of reserves as at end-2001 between developed fields, fields under appraisal, potential additional reserves and undiscovered recoverable reserves is shown in Figure 1 . Figure 2 shows the categorization of these reserves.
PILOT  is a group of industry and government leaders who are working in partnership to deliver quicker, smarter and sustainable energy solutions in the UKCS. As part of this activity an Undeveloped Discoveries Work Group was established in March 2000 to examine barriers to development. Their findings are summarized in Figure 3 and it can be seen that low deliverability was identified as a key barrier. The UK Department of Trade and Industry (DTI) was charged with the task of addressing this barrier and exploring how to unlock the potential from these undeveloped discoveries. A phased approach was adopted, which started by gathering information on existing techniques and latest technological developments.
The second phase of this initiative involved collating and analysing data on low deliverability prospects, in order to understand the reasons for their lack of development. There are many potential reasons for low deliverability, including:
Highly viscous oils
Poor reservoir connectivity
Low reservoir pressure
Kosztin, B. (Hungarian Oil and Gas Co.) | Palasthy, Gy. (Hungarian Oil and Gas Co.) | Udvari, F. (Hungarian Oil and Gas Co.) | Benedek, L. (Hungarian Oil and Gas Co.) | Lakatos, I. (Univ. Miskolc, Hungary) | Lakatos-Szabo, J. (Univ. Miskolc, Hungary)
A novel gel treatment technique based on transformation of water soluble Fe(III) compounds into gel-like precipitate by in-situ hydrolysis and flocculation was developed for water shut-off in mature oil fields. The new blocking material has excellent stability under field conditions, and yet simple remediation is possible in case of placement failures. Further, the novel method is characterized by self-controlling chemical mechanism and using this technique injectivity problems didn't arise even in low-permeability and tough formations.
The extensive field program was supported with special software determining the penetration distance from the wellbore. Based on log data, the pay zone was subdivided into a maximum of four layers assuming that crossflow among zones was negligible. Total volume of the treating fluids was obtained by asserting two limiting rules: the treating fluid must reach a minimum penetration depth (>15 m) in the layer having the highest permeability, but the max. penetration depth should not exceed 2 m in the layer having lowest permeability.
The test program comprised treatment of ten oil producing wells and seven water injectors. The well responses varied between wide limits: technical success was achieved in about 60 % of the wells, and the treatment was economically beneficial in about 40 % of the cases. In special reservoir blocks the injector wells were simultaneously treated with the oil wells. The primary goal of this project was to enhance the effect of flow profile correction around the producers and to improve the frontal displacement mechanism. The new method was compatible with the dirty sandstone reservoir systems, and there were no technical failures. The positive results contributed significantly to the operator's decision to extend use of the new method to other reservoirs.
The idea of water shut-off treatments raised already in 1922 when injection of silicate solutions into oil producing wells with the aim at gelation in-situ to form a blocking phase was patented. As far as the hydrocarbon industry is concerned, however, a real need to control flow profile around wells came to light only in the middle of the sixties. Since that time a great variety of polymer methods using polymer solutions, rigid and weak gels as diverting/blocking agents and disproportional permeability modifiers have been developed. Namely, application of inorganic compounds, if they were used at all, comprised mostly silicates neglecting other gel-forming substances. Therefore, the primary goal of this and some earlier papers dealing with application of silicates1-4 and metal hydroxides5-9 is to prove the feasibility, applicability and profitability of a novel well treatment method under field conditions which may represent an alternative solution, particularly in low permeable, tough reservoir systems where incompatibility problems may arise using the conventional polymer-based techniques.
Many gas reservoirs in the Adriatic Sea, offshore Italy, are formed of laminated, low permeability dirty sandstones, requiring gravel packing for sand control. Numerous gravel-packed wells are either sanded up and shut in, or are underperforming due to fines plugged gravel-pack screens, which cannot currently justify the expense of an immediate and cost-prohibitive full rig workover. Frac and packs are performed to increase productivity bypassing near wellbore damage, interconnecting multiple sandstone layers and decreasing fluid velocities in the formation, thus reducing fines production. Significant interest exists to enhance fracture performance, deferring and reducing re-completion costs.
This paper discusses various rigless performed rehabilitations of failed sand control completions, highlighting the evolution of fracture fluid selection, optimization of the fracture placement and achieved geometries with seawater-based visco-elastic surfactant fluids and the use of speciality glass fibers for fracture pack stabilization and enhanced proppant transport. This combined rehabilitation technique enabled screenless sand control completion and is allowing low cost rehabilitation of plugged or failed sand screens and the development of any numbers of gas layers which otherwise could not be drained using conventional sand control technologies. This completion technology potentially allows to significantly adding gas or oil reserves, the development of the normally by-passed upper gas layers, which would require costly workover re-completion using conventional technologies.
Procedures, experiences and results are presented, validating the -enhanced visco-elastic surfactant fracturing concept enabling screenless sandface completion for controlling sand production. Rigless rehabilitation has confirmed being an efficient solution and allows cost-effective production increase.
Evaluation of numerous fracturing treatments performed in the Adriatic Sea, confirmed the selected fracturing methods and fluids used were not optimizing gas production. In-depth analysis of past fracture performances showed that the conventional frac fluids in use cannot create the fracture geometries needed - wide and short - to produce the Adriatic Sea reservoirs effectively. Required mature tip-screen-out fractures are not obtainable with brine and polymer-based fluids; and fracture geometries are unfavorable in respect to fracture length and width - brine created fractures were not sufficient, HEC fluids generated fractures were too long and too narrow, for effective gas production.
Table 1 summarizes the results of the analysis using brine, HEC and the industry's first visco-elastic (VES) fracturing fluid (ClearFRAC) during fracturing lithologically similar nearby Emma gas field and the application of the visco-elastic fracturing fluid - also called VES - results accomplished on Giovanna gas field.
The measurement of true formation resistivity (Rt) in order to determine fluid saturations, has resulted in the development of a wide variety of wireline and logging while drilling (LWD) measurement systems. These devices are generally treated as independent systems when determining Rt and fluid volumetrics. However, the sensor technologies are > complementary, and all available data can be used together to effectively > reduce > uncertainties inherent in the single data sets. This results in more > accurate water saturation (Sw) calculations, and reduced reservoir uncertainties. Techniques, which will be discussed, are not limited to mathematical models and inversion, but include methodologies for identifying the best acquisition strategy in order to acquire the required data, correct preparation for geosteering and reservoir navigation.
The development of wireline tensor resistivity devices that are capable of measuring transverse electrical anisotropy has significantly improved the quantification of fluid saturations in thin bedded formations, and even thicker formation units drilled through at high apparent dip. Additional low contrast pay zones have also been identified which were missed by traditional techniques. In certain circumstances LWD measurements can be used to provide an initial qualitative assessment of electrical anisotropy, and determine if these specialised wireline measurements would be beneficial in order to quantify fluid saturations. The identification of these zones will be discussed with the benefits and limitations involved.
Where tensor resistivity data is available it can significantly improve the geological models used for geosteering. Incorporation of this data can predict anomalies not seen on simple models, which may be interpreted incorrectly resulting in unnecessary wellbore deviations, and loss of reservoir penetration. Examples of these effects, and their magnitude, will be used to demonstrate the importance of incorporating electrical anisotropy in the models.
There are three primary technologies for measuring the resistivity of formations around a wellbore in common use today: Induction, lateral and propagation. Each of these has been developed individually, for applications in different mud systems, for wireline and for logging while drilling (LWD). For each of these technologies the aim has been to measure the formation resistivity as accurately as possible, and each of them responds in a different way to wellbore effects, fluid invasion profiles, and other formation properties. The aim has generally been to remove as many of these effects from the individual measurements as possible resulting in a measurement of Rt: The resistivity of the formation away from the wellbore, free from these artifacts. This is then used to compute fluid saturations using an appropriate methodology.
The different resistivity technologies can now be combined, and instead of being problematic, their differences exploited. This not only permits the determination of Rt, but also other formation properties such as anisotropy and tensor resistivities Rh (horizontal resistivity parallel to anisotropy) and Rv (vertical resistivity perpendicular to anisotropy), leading to a more accurate determination of fluid saturations.
The measurement of tensor resistivity data, Rv and Rh, removes the sensitivity of an Rt measurement to wellbore deviation. Incorporation of these data into a 3-dimensional reservoir model allows the correct prediction of LWD measurements used for reservoir navigation, and optimization of the wellbore trajectory in the reservoir.