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Rossini, Stefano (Eni S.p.A) | Roppoli, Giulia (Eni S.p.A) | Mariotti, Pamela (Eni S.p.A) | Renna, Simona (Eni S.p.A) | Manotti, Matteo (Eni S.p.A) | Viareggio, Alberto (Eni S.p.A) | Biassoni, Laura (Eni S.p.A)
The management of produced water has become a main issue in petroleum industry due to the huge quantities to be dealt with. Produced Water Re-Injection (PWRI) allows combining disposal with Improved Oil Recovery (IOR) opportunities. Nevertheless, PWRI could damage the formation, eventually compromising field performances. Well impairment is a complex phenomenon depending on several aspects. This paper focuses on the impact of Oil In Water (OIW) in injectivity performance, validating lab predictions and field evidences.
A comprehensive review of field cases has been carried out, analyzing injection well performance with Production Data Analysis (PDA) tools together with water quality data. On a selection of field cases where OIW has been identified as main impairment reason, a workflow was established performing core flooding experiments to measure experimental loss of permeability with different content of OIW. Obtained results have been integrated by bibliographic research.
Field evidences showed a direct relationship between permeability reduction and hydrocarbon content; moreover, injectivity impairment measured on field data has been found to be comparable (same order of magnitude) with the permeability reduction measured on core flooding. Combining all data together, a common trend of injectivity reduction vs. OIW content has been extrapolated passing through the definition of Injectivity Index (II).
New water injection concept depends on several elements that could affect the overall project value, water quality requirements is one of them. Water quality rule of thumb can be found in literature, but each project basis of design is different. The proposed approach allows to preliminarily quantifying the expected well impairment as function of water quality. It can be used as a first tool to dimension treatment facilities in function of the reduction of injectivity that we can accept for any given reservoir. Obtained trend is representative of a subset of real field cases, where OIW content is the main impacting parameter on PWRI well damage.
In the late 1970's, it became necessary to convert to seawater as the source of injection water in the pressure support program of the North Uthmaniyah section of the Ghawar Field in Saudi Arabia. This peripheral waterflood had been initiated by Saudi Aramco in 1966 to maximize recovery of oil from the Arab 'D' limestone reservoir in this unique field, the largest in the world.
This paper will provide a brief introduction to the seawater processing facilities which includes over 400 kilometers of pipeline and can supply 4.2 MMBD of treated seawater.
The paper will also discuss Saudi Aramco efforts to study and mitigate declining well injectivities. Experience in water quality control, well stimulation efforts to improve injectivity, and analysis of well plugging characteristics/profiles and their relation to reservoir permeability will be covered. An empirical relationship between the injectivity index and the cumulative water injected has been published and is now being evaluated as a means of monitoring well plugging and, indirectly, to monitor water quality. Efforts made to minimize well plugging by improving seawater quality and by internally coating the seawater piping system are also discussed.
Finally, using solar-powered flow computers to measure water injection rates and run pressure fall-off surveys will be compared to the previously used analog flow meters and subsurface pressure fall-off bombs.
There are two different but associated problems in this gigantic seawater system. One is to maintain acceptable water quality to prevent excessive losses of well injectivity. The second is to control corrosion at a reasonable level. Only the first problem will be given maximum consideration in this paper. The second problem, although very important, will be tangentially addressed in this write-up. Although seawater injection was started in mid 1978, it was during 1982 when an abnormal reduction in well injectivity was observed. Once the problem was detected, a series of actions were initiated and then implemented to regain control of the system's water quality.
A Task Force was created in 1984 and a coherent plan was materialized into further and more comprehensive actions to bring the seawater system within acceptable water quality limits. The plan consisted in treating the seawater with high concentrations of biocide, scraping the lines more frequently and upgrading the seawater reclamation plants. The positive effects of this plan started to be noticed during 1985, however, it was not until 1986 when the water quality improved to acceptable values, comparable to those seen in 1979. A stage to fine tune and maintain the system at acceptable water quality values was initiated after 1986 and has been maintained until today. In addition to maintaining the water quality by chemical treatment and scraping of the piping system, the company initiated a project to internally coat portions of the piping system with fusion bonded epoxy. The results of this action are encouraging.
A one-well field test of nitrogen WAG (water alternating gas) injectivity was conducted to determine whether a reduction in water injectivity would occur after injection of nitrogen. A 40% reduction was observed immediately after nitrogen injection. Following three short WAG cycles, water injectivity increased to its pretest level with injection of a large volume of water.
The Jay/LEC field in Florida and Alabama is producing under unitized waterflood operations. Several papers describe this field's historical development. The field test described in this paper was undertaken as part of an engineering evaluation of injecting nitrogen and water alternately into the Jay/LEC field Smackover reservoir to determine the effect on a miscible gas tertiary process. Several operators of miscible WAG injection projects have encountered a reduction in water injectivity after gas injection. in two projects, water injectivity decreased significantly and operators speculated that either the precipitation of asphaltenes, trapped residual gas saturation, or movement of fine granules of reservoir rock caused declines in injectivity. These projects were unable to achieve oil production rates forecast because more than the anticipated time was required to inject planned water volumes. If a reduction in water injectivity occurs because of trapped carbon dioxide saturation, the high solubility of carbon dioxide in water should allow water injectivity to increase rapidly during the succeeding water injection cycle. In addition, injection wells may experience a slight increase in permeability and porosity due to the solution of carbon dioxide in water forming a weak acid. In a nitrogen WAG project, the low solubility of nitrogen in water will prevent the trapped gas saturation from changing significantly during the water injection phases of WAG injection. Several documented WAG projects using low-water-soluble gases have observed significant reductions in water injectivity, while significant reductions in water injectivity when high-water-soluble gases are used are not documented. Laboratory experiments were performed with cores from the Jay/LEC field in an attempt to determine whether a seduction in water injectivity would occur if nitrogen and water were injected alternately into the Smackover reservoir. The results of these experiments were inconsistent. Changing rock wettability and movement of formation fines may have contributed to the inconsistent results. Since laboratory experiments to provide a basis for predicting field injectivity were unsuccessful, and in light of reported poor field performance, a field test was carried out to determine whether nitrogen WAG injection into the Jay/LEC Smackover reservoir would reduce water injectivity. During the field test initiated in Aug. 1978, reservoir injectivities and transmissibilities of water and nitrogen were observed during three cycles of nitrogen followed by water injection into a Jay/LEC field well. The conventional Homer analysis interpretation technique did not provide definitive solutions. A technique consisting of plotting transmissibility vs. square root of shut-in time provided a useful tool for observing fluid banks in the reservoir and evaluating changes in water and gas injectivities.
To ensure the selection of a representative injection well and simplify interpretation of bottomhole pressure measurements, the following criteria were established. 1. Reservoir development in the injection well should be limited to one relatively thin zone. 2. The ratio of permeability-thickness to injection rates during the injectivity test should be representative of rates in injection wells if a fieldwide project is carried out
The precipitation of inorganic compounds by cation hydrolysis could be an alternative method to modify injection and production profiles. The precipitation in porous media can be caused by a pH increase as result of fluid-rock interactions, direct neutralization with base or thermal decomposition of a basic precursor, placed as additive. This paper ascertains the effects of precipitant solutions of zinc or aluminum salts, plus urea as basic precursor, on permeability, at reservoir conditions.
Flow tests were conducted in 30 cm Berea cores, at 140°C, 800 psi. Different injection schemes were tested, varying the number of precipitant solution batches, i.e. 1 and 2, and the shut-in time, i.e. 24 and 48 h. After that, fresh water was injected to determine permeability reduction, as well as the effect stability, along the core and in 3 sections of 10 cm each.
The results show 98% as maximum permeability reduction located mostly in the inlet section, while in the outlet section the maximal reduction achieved was 80%. In all cases, the effect was stable for at least 10 PV of water injected. Furthermore, permeability was not restored by 0.1 N HCl solutions. Precipitation occurs at T>70°C; it takes 2-4 hours at 80°C, and 40 min. at 140°C; enough time for the placement of the solution into porous media. Scanning electron microscopy images of the treated Berea cores demonstrated different shapes of particles precipitated, depending on the cation; all of them reduce permeability by filling the porous space.
The aforementioned results show that in-situ cations hydrolysis induced by basic precursor have the potential to modify injection and production profiles in the field, with some possible placement advantages.
Water injection profiles and production water are important factors that require optimization during the life of the enhanced oil recovery projects. They have incidence in oil producing rate and costs for treatment-disposal of produced water. Once water breakthrough, preferential flow channels form leaving oil-saturated areas not contacted by the displacing fluid. In such cases, high permeability areas must be isolated or sealed in order to divert injection fluids towards oil bearing zones.
Commonly sealing chemical technologies include gels1,2,3 and cements4,5. Nowadays, research on alternative technologies is looking for lower formulation and operational costs and placement advantages. Among these technologies is cation in-situ precipitation, subject of this paper.
The precipitation of NaCl and KCl by salting-out effect has already been evaluated in porous media at reservoir conditions. Although significant permeability reduction can be achieved, the final effect is not stable to water flow; in addition, the brines used can induce corrosion6. Other approach considers precipitation of hydroxides and oxyhydroxides by cation hydrolysis, either by addition of an alkali to metal salt solutions or by reaction of these solutions with carbonate minerals7,8. Lakatos et al.9 tested an iron hydroxide-based application in injector and producer wells in Algyö field, Hungary. Treatment scheme consisted in the neutralization, inside porous media, of acid solutions of FeCl3 by sequential injection of K2CO3. Preliminary evaluation of the results pointed 60% technical success and 40% of the treatment profitable, making the technology very attractive.
However, the above procedure may drive to precipitation in a relative small mixing section, yielding low efficiency treatment. On the other hand, the method based on the reservoir rock carbonate content is of limited application, and it could have competition between channel formation due to dissolution and pore plugging due to precipitation. In order to achieve full precipitation and plugging of the whole flooded section, basic precursors may be appropriate to use. These compounds hydrolyze under certain conditions of temperature, changing pH of medium and inducing precipitation by cation hydrolysis.
Bennion, D.B. (Hycal Energy Research Laboratories Ltd.) | Thomas, F.B. (Hycal Energy Research Laboratories Ltd.) | Imer, D. (Hycal Energy Research Laboratories Ltd.) | Ma, T. (Hycal Energy Research Laboratories Ltd.)