Mixing of injected seawater with formation brines may cause scale precipitation at production wells and surface facilities, but does not generally cause significant damage within the formation itself. Indeed, mixing within the reservoir may be beneficial, if the concentration of scaling ions is reduced due to ion stripping as the brine mixture approaches the production well1. One potential exception to this is when the availability of produced water for re-injection (PWRI) is insufficient to maintain voidage replacement, and must be supplemented with seawater. Under such circumstances, seawater and formation brine may be completely mixed before injection. This will not lead to a loss of injectivity if scale inhibitor chemicals are appropriately applied to the injected brine stream2.
However, scale inhibitors are retained by the reservoir rock as they are displaced away from the wellbore, resulting in the inhibitor front propagating more slowly than the saturation front - usually referred to as chemical retardation. As brine is displaced away from the injection well, the upshot is a growing zone of mixed brine with chemical concentration below the threshold required to inhibit the scaling reaction.
The question this paper considers that has not been addressed before is whether the ratio of produced water to seawater that is injected, the possibility of treating the injection brine mix with inhibitor, and field specific details such as the location of the injection wells relative to production wells and the aquifer can impact how this zone of unprotected mixed brine is displaced and reacts deep within the reservoir, away from both injection and production wells. If the scaling reaction can be limited to a region deep within the reservoir where the volume of rock is large compared with the potential mass of scale that may deposit, then the sulphate ions associated with seawater may be stripped from the brine mixture before the water is produced. Thus, by considered yet straightforward management of the PWRI scheme, it may be possible to protect the production wells from scale damage in a way that is not possible under conventional seawater injection. This hypothesis is tested using conventional reservoir simulators and reaction-transport modelling. Various conditions are considered, including brine reactions, extent of brine displacement through the oil leg or aquifer, as well as management of the PWRI wells. Prediction of scale damage potential at production wells is made for an example field system.
Viscoelastic surfactant (VES) fluids have been widely used as gravel-packing, frac-packing and fracturing fluids for more than a decade because the fluids exhibit excellent rheological properties and maintain low formation damage characteristics compared with crosslinked-polymer fluids. Due to its non-wall-building property, VES fluid has much higher fluid leak-off into the reservoir matrix than wall-building polymer fluid. For frac-packing this has limited VES use to reservoirs with permeability of less than 1000 md and, in most cases, less than 250 md. Excessive fluid leak-off also significantly increases the cost of treatment.
This paper will introduce new technology for controlling the fluid loss of VES fluids to about 300ºF. New fluid loss control agents have been developed that, through chemisorption and surface charge attraction, associate with VES micelles to produce a pseudo-filtercake of viscous VES fluid that significantly reduces the rate of fluid loss. Use of this technology will reduce the VES fluid volume required for a given treatment by up to two-thirds and extends the permeability range of VES fluids to about 2000 md. The fluid loss control agents are slowly water-soluble particles that are used at relatively low concentrations. The particles will be dissolved and/or flowed back with the producing fluid. The rate of the pseudo-filtercake clean-up is enhanced by use of internal VES breakers. The results of rheology, leak-off, and core flow tests will be presented for the VES fluid systems at temperatures 150°F and 250°F.
This paper presents the results of laboratory studies and field case histories of a remedial treatment technique using a low-viscosity consolidation fluid system that is placed into the propped fractures by coiled tubing (CT) or jointed pipe coupled with a pressure pulsing tool. The treatment fluids are designed to provide consolidation (for previously placed proppant) near the wellbore to glue the proppant grains in place without damaging the permeability of the proppant pack.
Laboratory flow testing indicates that the proppant pack in a fracture model under closure stress only requires low-strength bonds between proppant grains to withstand high production flow rates. The consolidation treatment transforms the loosely packed proppant in the fractures and the formation sand close to the wellbore into a cohesive, consolidated, yet highly permeable pack. Field case histories are presented and the treatment procedures, precautions, and recommendations for implementing the treatment process are discussed. One major advantage of this remedial treatment method is the ability to place the treatment fluid into the propped fractures, regardless of the number of perforation intervals and the length of the perforated intervals without mechanical isolation between the intervals. The fluid placement efficiency of this process makes remediation economically feasible, especially in wells with marginal reserves.
The Bonga field, which is located in deep water off the Nigerian coast, started oil production at the end of 2005. In order to sustain production, seawater injection started from the beginning of the oil production at a rate of 300k bwpd. During the field development it was concluded that seawater injection in Bonga would result in reservoir souring, and that mitigation was necessary. Initially the selected strategy for Bonga seawater injection was to control reservoir souring with biocide and handle low levels of H2S with sour service materials and scavenging facilities topside. The maximum H2S the existing facilities could handle was set at 50 ppm (v).
The decision to control reservoir souring with biocide and handle H2S at surface was re-evaluated in 2003, and it was concluded that there would be a risk that the maximum allowable H2S content in the facilities (i.e. 50 ppm(v)) might be exceeded during the life time of the project. Given the positive experience with the injection of nitrate in other seawater floods throughout the industry, nitrate was selected as the mitigation method and injection started directly at the beginning of the waterflood at the end of 2005. As such Bonga is one of the first waterfloods where nitrate is being used to prevent reservoir souring, the main application so far has been to reduce H2S in already sour fields.
This paper presents the experience gained with the nitrate injection during the first period of the Bonga waterflood. Issues like logistics and how to ensure nitrate is applied correctly are discussed in more detail. In addition laboratory testing executed to define an appropriate nitrate injection rate under Bonga conditions are also presented.
After several months of operation the Minox unit to remove the bulk of the oxygen broke down and oxygen control was done with chemical oxygen scavenger only. With this different mode of operation, the effectiveness of the nitrate as souring mitigation method was expected to be affected. Additional laboratory experiments, also reported in this paper, were performed and did not indicate any issue with respect to the predicted souring.
This paper discusses the development of a holistic water and scale management plan for a green-field development, which faces a new order of scale management challenges. Specifically, this paper documents a scale risk assessment and the development of a scale management plan during the front-end engineering design of the Tombua-Landana development in West Africa. The complexity of scale management is compounded by the presence of multiple reservoirs with very different scaling potentials and by the plans for produced water reinjection. The objective of the study was to define a complete scale management plan, which incorporates flexibility for future unknowns and minimizes the total cost of scale management, without over-capitalization.
The Tombua-Landana field will produce from multiple reservoirs that incorporate several distinct formation waters with barium content as high as 800 mg/l and will require seawater injection for reservoir pressure maintenance from day one. Scaling tendency predictions were made for the major groups of formation water, both with and without seawater injection. In addition, a variety of produced water reinjection scenarios were investigated.
Due to the predicted severity of barite scaling, it was determined that scale would not be effectively controlled solely by scale inhibitor chemicals. It was therefore necessary to investigate alternative mitigation strategies, primarily sulfate removal. The impact of sulfate ion removal from seawater on barite scaling was investigated in order to determine the level of sulfate ion removal that would be necessary for each water type to limit the extent of scale deposition to a level that most residual scaling could be controlled by downhole chemical injection.
Because of the considerable cost associated with processing low sulfate injection water, it was necessary to optimize the size of the sulfate removal membranes (SRM) primarily by using produced water reinjection.
This field study typifies several industry trends in inorganic scale management: (i) Deepwater West Africa is emerging as a new focus area for sulfate scaling; (ii) Deepwater economics require co-production of multiple reservoirs in order to reach threshold reserves and will necessitate the installation of major infrastructures; (iii) Economic and environmental drivers support the use of produced water reinjection, even though this exacerbates water compatibility problems and creates new challenges for reservoir monitoring.
Traditional aromatic and chlorinated solvents typically utilized in oilfield applications are facing stricter governmental and environmental restrictions for their use and disposal. Concerns about flammability, acute toxicity, and environmental contamination have made their use less attractive. Furthermore, many countries in Central and South America have begun to closely monitor and regulate the manufacture, importation, and storage of typically utilized oilfield solvents such xylene and toluene due to their utilization in the manufacture of illicit drugs.
In an effort to be environmentally and socially responsible, greener alternative solvents from renewable resources are continually being investigated as possible cleaning and solvent solution substitutes. This paper discusses the properties and evaluation of a 100% biodegradable non-toxic solvent blend that is derived from two renewable resources produced both in the U.S. and world. In the past, due to its price and limited availability, the solvent's use has been limited to specialized cleaning applications in the electronics industry. However, due to improved manufacturing processes, the product is more available and affordable for wider applications. The totally biodegradable solvent blend is currently being utilized heavily in paint and coatings removal, ink and graffiti removal, and electronics component cleaning. It has a Kauri Butanol (KB) solvency value of approximately 500 and is a EPA approved SNAP solvent.
This paper discusses the evaluation of the biodegradable solvent blend to replace traditional solvents in stimulation packages for wellbore and formation cleaning applications. Laboratory studies were conducted to evaluate the solvent's efficiency to dissolve and remove pipe dope materials and OB/SOB mud residues and films at room temperature and 150°F. The solvent was also evaluated to determine its efficiency to dissolve and disperse paraffin and asphaltene solids, and to reduce the viscosity and enhance the flow characteristics of heavy crude oils.
Formation fluid influx into cement slurries immediately after placement presents not only a short-term problem, for example losing the slurry due to shallow water flows, but also presents a long-term problem, for example gas flow and pressure buildup behind the casing. It is critical that cement slurries be designed carefully when such problems are anticipated. Cement slurries that often offer the best solution to resist the formation influx are those that do not gel while being pumped then gel/set and gain strength rapidly once placed. These are sometimes referred to as "right-angle set?? cements and should possess the following attributes in laboratory design testing:
This paper shows that although a cement slurry having a "right-angle set?? may ensure the first two benefits, it does not always guarantee the latter two when present behind a casing. For example, some slurries might reach thickening time and become unpumpable rapidly, but strength development may not occur until long afterward, due to a time lag between thickening and hydration time (set time) of cement. In such cases, slurry should be designed such that the thickening time and hydration time are essentially identical. Novel slurries that maintain low rheological profiles while the slurry is being placed, then set and gain strength quickly due to cement hydration afterward, have been developed for a variety of densities and downhole temperatures. Results from laboratory and related field case histories will be presented.
This paper describes a sensitivity study on the main factors affecting a polymeric Relative Permeability Modifier (RPM) treatment in the near wellbore region of a mature oil producing well. The study is divided into several parts where various factors, which affect the application of RPM technology in a chosen field base case well, are studied. These factors include the effects of instantaneous vs. kinetic adsorption for the treatment and the further influence of treatment properties, reservoir fluid properties and the reservoir formation. From the sensitivity study, we can conclude that the most influential factors in the treatment response, i.e. the water cut reduction, are the combination of polymer adsorption type (kinetic or equilibrium) with method of application of the resistance factors (threshold or variable), resistance factor ratio, reservoir fluid properties and reservoir layout. On the other hand, the polymer viscosifying effect is not such an influencing factor, and neither are the shear stress, salinity, hardness and pH that subsequently affect this property.
The sensitivity study was carried out using a model capable of describing RPM treatments in the near wellbore region. The model is a radial, isothermal, two-phase, multicomponent and multi-layer mathematical model. The model considers the immiscible displacement of the oil and water phases along with polymer transport in the aqueous phase. The various phenomena that describe polymer flow through a porous medium are also considered and modelled. For each of the various physical phenomena (e.g. adsorption, fluid rheology, resistance factor, etc.), we must then make decisions about its behaviour, which is simulated by choosing certain models and the parameters in these models. For multi-layer systems, the model considers no vertical communication between layers, thus the pressure drop across the various layers remains equal. The model includes kinetic adsorption and the application of resistance factors based on a polymer adsorption threshold, which are not normally available in other models. The model has been verified by comparison with both analytical solutions and Eclipse 100 results and novel observations of kinetic and equilibrium adsorption in radial coordinates are described.
Kotlar, Hans Kristian (Statoil ASA) | Wentzel, Alexander (Norwegian University of Science and Technology, NTNU) | Throne-Holst, Mimmi (SINTEF Materilas and Chemistry) | Zotchev, Sergey (Norwegian University of Science and Technology, NTNU) | Ellingsen, Trond (SINTEF Materilas and Chemistry)
Paraffins, mainly composed of long chain alkanes (LCA), pose a problem in the recovery of oil from fields producing paraffinic oil. This is due to the build up of paraffin deposits. Solidification and aggregation of LCA can cause serious problems in oil recovery due to the clogging of oil production pipes, deposits in the process equipments and sealing off pores in the reservoirs. Partial degradation, i.e. reduction in chain length of LCA present in such oils is likely to greatly increase its quality as well as enhance the recovery.
The approach presented in this paper is the development of biocatalytic processes involving bacteria capable of degrading LCA in situ. The project has focused on the identification of bacterial strains capable of LCA degradation and the search for and characterization of enzymes therein. One strain, identified as Acinetobacter sp. 6A2, was isolated by screening for strains capable of utilizing a paraffin with a melting point of 52-54oC. The strain was shown to be able to degrade alkanes with a chain length ranging from C10 to C40. Three enzyme systems have been identified showing overlapping alkane substrate specificities in this strain, two AlkM-type alkane hydroxylase homologues, AlkMa and AlkMb, and one system encoded by a gene given the name almA. AlkMa and AlkMb are involved in the degradation of C10 to C20 alkanes. AlmA, however, is involved in the degradation of LCA with a chain length of C30 to C40. This is confirmed in growth experiments of mutant strains. The AlmA enzyme is of particular interest as it is involved in the degradation of the more heavy wax components.
Efficiency and specificity of the enzyme systems are currently under investigation.
This paper presents field results from scale squeeze treatments carried out on platform wells within a high temperature (150C) field in the Norwegian sector of the North Sea. Scale control and the resulting squeeze treatments to production wells were highlighted as the most expensive item in the production chemical budget. The development of a cost-effective squeeze and monitoring policy has been critical to reducing the operating cost of this asset as the produced water cut rose.
The decision to use both aqueous and emulsified scale inhibitor for treating these high temperature production wells was arrived at after an extensive series of laboratory tests including formation damage coreflood studies and an assessment of chemical retention at this elevated temperature. The field data from these wells will be presented comparing treatment lifetimes and clean up rates between conventional treatments and the novel emulsion technology
A key factor to the success of such treatment is an understanding of chemical placement and the effectiveness of the treatment chemicals. Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs and more recently probes have been developed which increase the rate of evaluation/interpretation. All these monitoring methods prove that the chemical is present in the brine when sampled or that scale formation is not occurring at the point of brine analysis. This paper outlines the experimental methods developed to evaluate the suspended solids collected from the produced brine by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced fluids. The combination of these methods has improved the integrated scale management program in terms of evaluating scale squeeze placement effectiveness, squeeze lifetime and provides the confidence t0 extend the period between scale squeeze treatments. Also, and in some cases treatments were stopped where brine analysis alone would have suggested further scale squeeze applications were required.