A field trial was conducted in June, 2001, of a downhole fiber optic two-phase flowmeter in two wells at PDO's Nimr field in Oman. The fiber optic flowmeter provides real-time measurements of volumetric flow rate and water cut. The purpose of the field trial was to evaluate the performance of the flowmeter for potential application at Nimr. Specifically, objectives were to determine the deployability of the flowmeter at Nimr, to determine the ability to operate with heavy, viscous Nimr crude, and to determine the ability of the flowmeter to distinguish between high water cut legs in dual lateral completions with artificial lift. Accuracy goals for the flowmeter were ±3% on water cut and ±10% on total volumetric flow rate.
The fiber optic flowmeter was successfully installed in two wells at Nimr. In one of the wells the meter was installed in the completion string just below an electrical submersible pump (ESP) and in the other well it was installed just below a beam pump. A surface Coriolis mass flow meter served as a reference for the two-week field trial. In the beam-pumped well it was found the noise environment is not compatible with the physical measurement principle of the optical flowmeter, and a comparison against the surface-measured rates was not possible. In the ESP-pumped well, comparison of the flow rates and water cut measured by the fiber optic flowmeter and the Coriolis meter were better than expected, -1% to +2% on water cut and -1% to +3% on total rate, and well within specifications.
The Nimr field is located in southern Oman in the South Oman Salt Basin, Fig. 1. It was discovered in 1980 and is the second largest oil field in Oman, with current production of about 27,000 m3/d of oil from over 300 wells. The field produces from hydrostatically pressured sandstone reservoirs at a depth of about 900 m. Reservoir temperatures and pressures are approximately 51°C and 9,500 kPa. Artificial lift for the fluids at Nimr is provided by ESP's and beam pumps.
Nimr produces a viscous (200-400 cp), heavy (21°API) crude oil that contains no appreciable solution gas, with a gas-oil ratio of about 0.6 sm3/m3. production is supported by a bottom water drive. An unfavorable mobility contrast between the oil and formation water results in rapid water breakthrough, and a large portion of a well's reserves are produced at high water cuts. The average economic limit of Nimr wells is about 98% water cut. Thus, water management plays a key role in well economics.
Initial field development used a grid pattern of vertical producers. This was switched to a grid of horizontal wells in the 1990's, with wells located at the crest of the structure. Each horizontal producer develops a "tent" of oil beneath it, as shown in Fig. 2, with the optimum spacing of wells driven by viscosity contrast between the oil and water, the thickness of the oil column, and the vertical-to-horizontal permeability ratio.
In 1997, a Field Development Plan was implemented which involved drilling dual lateral wells to connect two horizontal grid locations to a common vertical mother bore and surface hookup. The advantage of using dual laterals is a reduction in the number of wells required to drain the field and a corresponding reduction in capital expense. This is balanced by a decreased ability to monitor and control water production from individual horizontal legs at the surface. Heterogeneities in the reservoir can result in water breakthrough in one leg of the well before the other. This will impact the ultimate expected recovery and the required capacity of facilities for processing and disposing of the produced water.
The Dacion field, located in the eastern Venezuelan basin, came on production about 50 years ago. In the early years of development, more than 300 wells were drilled and production reached a peak of 45000 bbl/D of oil around 1958. Subsequently, the field was operated on a rate maintenance basis, with a drastic reduction in drilling activity. By 1997 the rate had fallen to approximately 10000 stb/D, and the field was included in the Venezuelan third licensing round. Lasmo Venezuela was awarded the management of the Dacion asset, and started an aggressive drilling program of additional replacement and infill wells. This led to production tripling in 2 years, associated, however, with increasing water production. Unconventional treatment options had to be considered for managing the water, due to the reservoir complexity.
The Dual Flow concept is one of such techniques. It is based on perforating both oil and water layers and producing from each set of perforations separately. Reservoir simulations showed the viability of the technique by allowing an increase in the critical production rates. Controlling the cone leads to a reduction in water production from the upper set of perforations and hence the water processing requirement. The implementation and the results from the first pilot well are presented, including the lessons learned. A comparison with predicted performance is provided. The pilot study highlighted a number of critical issues for produced water management, including the impact of permanent monitoring and control.
The Dacion block was awarded to Lasmo Venezuela in June 1997. In April 1998, Lasmo, now a division of ENI, took over operations from Corpoven, now PDVSA, and is currently operating on behalf of PDVSA. This field, as part of the third licensing round in Venezuela, was one of several mature asset rehabilitation projects.
The main objective when taking over a mature field is firstly, to understand what constrained the production of the past and secondly, to assess what is the possible impact on future performance by reducing these limitations. In Venezuela, Colombia and Ecuador water handling limitations are the main issues. Many fields produce at excessive water cuts (50 percent and above) and field developments are, undesirably, more about water cycling than oil production The work described in this paper concentrates on the Dacion field development in Venezuela, but is relevant to many fields in the region.
In the Dacion block the reservoirs have, in general, adequate pressure supported by natural aquifers. The oil gravity is in the 15 to 25 API range with corresponding oil viscosities in the 8 to 20 cP range. The main producing horizons can exhibit large permeability values of 2 Darcy or more. An unfavorable mobility ratio is therefore dominant and as a result the oil production is associated with significant water production. Furthermore, due to high permeability at the base of most sand members, water underride is taking place throughout the area. In the past the production was limited by fluid handling capacities at surface and, consequently, the main objective in this rehabilitation project has primarily been to reduce the water handling constraint and cost. This impact has been sought in two directions, either by seeking ways of reducing associated water production and/or by searching for cheaper water handling costs.
A system has been developed and tested that reduces the production from zones producing high water cut in open hole screen completions. By use of flotation balls with neutral density in formation water, the system automatically reduces a nozzle area on each joint with increasing water cut. The oil selective inflow control system (OS) is used to reduce flow from zones that significantly contribute to the water cut in a well.
A reservoir simulation tool has been configured to incorporate the OS functionality.
Most oil wells that penetrate more than one reservoir zone or penetrate long reservoir intervals may benefit from inflow control to limit water and gas production. Sliding sleeves or smart well systems are expensive and time consuming to install and are proven to pose reliability challenges, flow area constraints and other limitations. Inflow control devices (ICD) (passive chokes or capillary flow paths) have been used in long horizontal wells primarily in the Norsk Hydro Troll Field with success to delay gas coning. By sizing the chokes, the sandface pressure along the wellbore is made more uniform. This results in better areal drainage. ICDs were in the Grane field simulated with ECLIPSE and NETool reservoir simulation software, but did not provide gains in production rates or ultimate recovery to increase the NPV of the field. This is mainly decided by high oil viscosity and the larger importance of water influxes in Grane, than on Troll. It was decided to study the possibilities and impact of an Oil Selective inflow control system (OS). A test and simulation program was set up between EWS and Norsk Hydro to verify the functionality and operational limitations for an OS in the Grane field.
The Grane Field
Grane is operated by Norsk Hydro and lies in the southern part of the North Sea, Norwegian Sector. The reservoir has excellent reservoir properties.
In this paper, we first provide guidelines for selecting the most appropriate permanent downhole sensor or combination of sensors for reservoir monitoring, given fluid and rock characteristics. This selection is applied to pressure, electrical, and seismic sensors, based on their respective response equations to formation and rock properties.
We then present two synthetic cases illustrating the interpretation of permanent monitoring data, with emphasis on the benefits of data fusion and data assimilation, referring respectively to the use of multisensor and time-lapse data; more specifically, we show how those approaches enhance the convergence of the inversion process towards the solution.
One important challenge for reservoir management in the coming decade is to monitor fluid movements in hydrocarbon reservoirs, with the goal of optimizing their drainage. Three main physical principles can be envisaged: resistivity, pressure response to well tests, and acoustics (or seismics), since changes in resistivity, mobility, and elastic properties are expected at a front location in a hydrocarbon reservoir.
To this end, permanent downhole sensors such as pressure gauges, electrode or geophone arrays have therefore been1 or are currently being developed. Arrays of such sensors would allow repeatedly conducting reservoir surveys around the instrumented wells.
Because different tools are sensitive to different reservoir and fluid properties, sensor-screening criteria have to be established to take the full benefit of investing in such a technology. This is dealt with, in this paper, by proposing a simple graphical method that will help in choosing the optimal single sensor or the combination of sensors best suited to a given problem and environment.
Once the selected sensors have been deployed, interpreting the data recorded by the sensors to obtain information on the fluid movement within the reservoir requires an inversion process. This inversion process can be improved by taking advantage of time-lapse acquisition (i.e., data assimilation2) and/or by the concurrent use of different types of sensor (i.e., data fusion3).
In this paper, two synthetic examples are used to illustrate the use of permanently acquired data in a waterflood characterization context. The first example deals with the determination of a water-injection front movement from a simultaneous inversion of pressure, electrical potential, and seismic data, showing how their joint use can alleviate the indetermination on the front geometry parameters to be inverted.
In the second example, we show how information about relative permeabilities can be derived from interpreting a continuous stream of flow rate and electrode-array potential data. In particular, we show how the time-lapse nature of the acquisition can be used to obtain better parameter estimates.
Sensor Response Equations
Selection of a wellbore sensor, such as a rate measurement device, is relatively straightforward, given the anticipated multiphasic well production and the device's nominal characteristics. By contrast, selecting one (or several) reservoir sensor(s) may be a much more difficult task, given the large number of reservoir and fluid properties that are influencing the measurement(s). One should therefore return to the response equation of each sensor to evaluate the sensitivity of a particular measurement to a given set of reservoir parameters.
The following equations correspond to the response of resistivity, seismic, and pressure sensors for the situation depicted in Fig. 1; i.e., the simple case of a vertical water-front movement across a homogeneous oil-bearing reservoir. The sensors are located in the producing well, and the distance between the sensor and the front at time? is L(t).
We have created a variety of detailed geological models, in order to carry out a sensitivity study in a turbidite oil reservoir. The base case stochastic model was generated using well-log data, seismic attribute data and information from outcrop analogues. In addition, some small-scale models were created to capture the effects of fine sedimentary structure (mudstone intra-clasts, and interbedded sandstone and mudstone layers).
The main focus of this paper is on the flow simulation, upscaling and sensitivity analysis, rather than on the geological modelling. We carried out a range of sensitivity studies on two-phase flow parameters, gridding effects and upscaling. Our results show that the large-scale geological structure is potentially dominant. Integration of seismic information and the definition of zone transitions is crucial if an adequate history match is to be obtained. Redistributing the facies by successive realisations also impacted strongly on the productivity. The dominant two-phase flow property was wettability, particularly the shape of the capillary pressure curve, which could lead to a large capillary transition zone.
In this particular field, the fine-scale structure, as modelled for two genetic units, did not have a large impact on the results, because these units occurred in isolated regions and were largely by-passed. Small scale heterogeneity in the main Channel Sandstone genetic unit did impact on flow, however.
Reservoir model building and flow simulation is an important method applied to improve understanding of reservoir architecture as well as prediction and management of production performance. Reasonable modelling procedures must be applied to capture the effect of the important elements of a depositional system, including heterogenetiy variation at different scales (e.g. Kjonsvik et al., 1994; Jones et al. 1995). Such procedures are often executed by building geo-cellular models with horizontal cell sizes of the order of 10's of metres and a thickness of the order of a metre. The model may be populated stochastically, conditioned to well and seismic data, use rules that capture depositional processes and should produce geologically realistic results. Upscaling the flow parameters in these models is necessary to produce simulation models that can be used to predict reservoir performance and estimate uncertainty. The size of cells in the geocellular models is usually too large, however, and additional modelling of small scale heterogeneity and upscaling is often required.
In recent years, the Deep Marine Module of the Genetic Units Project, at Heriot-Watt University, has developed considerable experience analysing outcrop and reservoir data with a view to modelling deep marine reservoirs (e. g. Clark and Good, 1997; Clark and Good, 1998; Pringle et al., 1999; Clark and Stanbrook, 2001; Stephen et al., 2001a). The Heterogeneity Project has developed and applied a number of methods of flow simulation and upscaling, including the Geopseudo Method (e. g. Corbett et al., 1992; Ringrose et al., 1993; Huang et al., 1995; Ringrose et al., 1999; Pickup et al., 2000; Pickup and Stephen, 2000; Stephen and Pickup, 2000; Stephen et al., 2001b). The aim of this study was to integrate geological modelling approaches with methods of fluid flow simulation and upscaling to improve oil recovery predictions and to quantify uncertainty. The study was applied to a field reservoir, owned by a sponsor of both projects. A full-field data set was supplied, including seismic attribute data, extensive well data (four cored wells and another 11 logged) and production data.
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).
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
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.
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.
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.