Formation damage: Do we always need to have a high focus on its prevention, or do occasions exist when it really does not matter? This paper describes a coreflooding program performed with sandpacks at different permeabilities, water qualities, and injection conditions. Because of inherent complexities, understanding the characteristics of perforations in downhole environments is a significant challenge. Perforation-flow laboratories have been used to provide insight into cleanup and productivity mechanisms around perforation tunnels. A high-carbon-dioxide (CO2) carbonate gas field offshore Sarawak, Malaysia, is scheduled for development.
With the purchase, the growing, privately-held Chrysaor Holdings will expand its UK North Sea production to 185,000 BOE/D. The state-run offshore company has found a gas and condensate field that holds an estimated 250 million BOE. The latest example of the offshore sector's march toward automated wellbore construction will take shape later this year in the North Sea. Just 2 months after issuing more than a hundred licenses, the Oil and Gas Authority begins the process again for a whole new set of blocks. The company announced it would “initiate the process” of marketing its UK Central North Sea fields as part of a portfolio review.
Geochemical scale formation and deposition in reservoir is a common problem in upstream oil and gas industry, which results in equipment corrosion, wellbore plugging, and production decline. In unconventional reservoirs, the negative effect of scale formation becomes more pronounced as it can severely damage the conductivity of hydraulic fractures. Hence, it is necessary to predict the effect of scale deposition on fracture conductivity and production performance.
In this work, an integrated reactive-transport simulator is utilized to model geochemical reactions along with transport equations in conventional and unconventional reservoirs considering the damage to the fracture and formation matrix. Hence, a compositional reservoir simulator (UTCOMP), which is integrated with IPhreeqc, is utilized to predict geochemical scale formation in formation matrix and hydraulic fractures. IPhreeqc offers extensive capabilities for modeling geochemical reactions including local thermodynamic equilibrium and kinetics. Based on the amount of scale formation, porosity, permeability, and fracture aperture are modified to determine the production loss. The results suggested that interaction of the formation water/brine and injection water/hydraulic fracturing fluid is the primary cause for scale formation. The physicochemical properties such as pressure, temperature, and
During hydraulic fracturing, precipitation of barite and dissolution of calcite are identified to be the main reactions, which occur as a result of interaction between the formation brine, formation mineral composition, and injection water/hydraulic fracturing fluid. Calcite dissolution can increase the matrix porosity and permeability while barite precipitation has an opposite effect. Therefore, the overall effect and final results depend on several parameters such as HFF composition, HFF injection rate, and formation mineral/brine. Based on the fracturing fluid composition and its invasion depth in this study, the effect of barite precipitation was dominant with negative impact on cumulative gas production. The outcome of this study is a comprehensive tool for prediction of scale deposition in the reservoir which can help operators to select optimum fracturing fluid and operating conditions.
Chemical EOR is an increasingly employed approach used to enhance oil recovery by combining changes in fluids mobility, macroscopic sweep, interfacial tension, etc. to essentially improve, or extend the economic life of a water flood. It includes flooding with polymer, surfactant, alkaline/surfactant, alkaline-surfactant-polymer (ASP), CO2 and / or other miscible gases which is often combined with waterflood (
The paper evaluates the main chemical changes that occur in the system for each EOR approach –– and shows how these changes, including in situ reservoir reactions and the stability/instability of the EOR packages themselves can exacerbate a range of PC-related challenges especially when considering the likely production of up to three different fluids: formation water, the EOR flood medium and any previous flood water from previous secondary recovery
The paper includes modelling results, laboratory results to validate model predictions as well as examples from field case studies to illustrate the impact of the chemical changes referred to above. Specific highlights include the impact of the use of either high- or low-pH EOR fluids on scale control, corrosion control and asphaltenes control; for scale it examines both inhibitor performance
The overall conclusion is that chemical EOR can have significant impact on PC and that these should not just be considered at the design stage and not just for the injection system but also to take into account the impact these may have on production wells following breakthrough of flood waters, showing that essentially each new or exacerbated PC issues can be predicted or at least anticipated with the required degree of confidence before implementation of EOR.
Produced water composition analysis provides evidence of what geochemical reactions are taking place in the reservoir. This information can be useful for predicting and managing oilfield mineral scale resulting from brine supersaturation.
This paper presents results of a study of the produced brine compositions from three wells in a field operated in the North Sea, with geochemical modelling complementing the analysis. The findings presented in this work provide evidence of magnesium depletion and sulphate retardation in a sandstone reservoir at 130° C.
This adjusted formation water composition was then used for calculations of the injection water fraction in each of the produced water samples. The Reacting Ions Toolkit was used to plot data in a variety of formats, including ion concentration vs. ion concentration, ion concentration vs. injection water fraction and ion concentration vs. time to identify trends and to examine the extent of involvement of the various ions in geochemical reactions.
The breakthrough of sulphate, a component primarily introduced during seawater flooding, was retarded during injection water breakthrough. Observed sulphate concentrations were lower than predicted for the case of brine/brine interactions only. The implication of this sulphate reduction was lower minimum inhibitor concentration required to control scale formation and longer squeeze treatment lifetimes for the operator.
A brine/rock interaction mechanism was proposed that involves magnesium depletion and is reproduced in the reactive transport model. 1D reactive transport modelling was performed to match possible
The evidence from the produced-brine chemistry suggests that the Gyda field has experienced a variety of geochemical reactions caused by the high temperature and initial calcium (Ca) concentration, and so it is worth reviewing the produced-water data set and studying what in-situ geochemical reactions may be taking place.
Produced-brine-chemistry data from 16 wells in the Gyda field are plotted and analyzed in combination with general geological information and the reservoir description. A 1D reactive-transport model is developed to identify the possible geochemical reactions occurring within the reservoir triggered by seawater injection, and then extended with the inclusion of thermal modeling and also to be a 2D vertical-cross-section model.
Three possible classes of formation-water composition in different regions of the Gyda field have been identified by analysis of the produced-water data set. Anhydrite and barite precipitation are the two dominant mineral reactions taking place deep within the reservoir. Magnesium (Mg) stripping may be a result of multicomponent ion exchange (MIE), dolomite precipitation, or a combination of both. Reservoir temperature is lowered during coldwater injection. The solubility of anhydrite increases at lower temperature, and anhydrite will gradually dissolve in response to the movement of the temperature front, which is much slower than the formation/injection-water mixing front. The extent of mineral precipitation within the reservoir can be reduced by the heterogeneity; the modeling shows that the extent of ion stripping caused by mineral reactions in the reservoir is greatest when simulating a single uniform layer. Brine mixing and the occurrence of geochemical reactions caused by vertical mixing are not observable, even when assigning a high vertical permeability in a heterogeneous model.
Thermal modeling is included to evaluate the effect of nonisothermal processes and heat transport on the geochemical reactions, especially the anhydrite mineral reaction. We have investigated how the difference in horizontal permeability in the two layers affects brine mixing of formation and injection water and geochemical reactions.
Produced water was sampled and measured repeatedly during production from an offshore field, and an extensive brine-chemistry data set was developed. Systematic analysis of this data set enables an in-depth study of brine/brine and brine/rock interactions occurring in the reservoir, with the objective of improving the prediction and management of scale formation, along with improving its prevention and remediation.
A study of the individual-ion trends in the produced brine by use of the plot types developed for the reacting-ions toolkit (Ishkov et al. 2009) provides insights into the components that are involved in in-situ geochemical reactions as the brines are displaced through the reservoir, and how the precipitation and dissolution of minerals and the ion-exchange reactions occurring within the reservoir can be identified. This information is then used to better evaluate the scale risk at the production wells.
A thermodynamic prediction model is used to calculate the risk of scale precipitation in a series of individual produced-water samples, thus providing an evaluation of the actual scaling risk in these samples, rather than the usual theoretical estimate, on the basis of the endpoint formation- and injection-brine compositions and the erroneous assumption that no reactions in the reservoir impact the produced-water composition. Nonetheless, the usual effects of temperature, pressure, and brine composition are accounted for in these calculations by use of classical thermodynamics. The comparison of theoretical and actual results indicates that geochemical reactions taking place in this given reservoir lead to ion depletion, which greatly reduces the severity and potential for scale formation. However, ion-exchange reactions are also observed, and these too affect the scale risk and the effectiveness of scale inhibitors in preventing deposition.
Additionally, comprehensive analysis by use of a geochemical model is conducted to predict the evolution of the produced-brine compositions at the production wells and to test the assumptions about which in-situ reactions are occurring. A good match between the predictions from this geochemical model and the observed produced-brine compositions is obtained, suggesting that the key reactions included in the geochemical model are representative of actual field behavior. This helps to establish confidence that the model can be used as a predictive tool in this field.
In waterflooded reservoirs under active scale management produced water samples are routinely collected and analysed, yielding information on the evolving variations in chemical composition. These produced water chemical compositional data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale management programmes designed to minimise damage and enable improved recovery.
In this interdisciplinary paper, the analyses of produced water compositional data from the Miller Field are presented and a 1D reactive transport model is developed to study possible geochemical reactions taking place within the reservoir through matching model results with observed produced water data. However, in the 1D reactive transport model, only one flow path was simulated; this does not fully represent the fluid flow and mixing behaviour in the reservoir.
Therefore, this paper also presents a fully 3D reservoir simulation study for the Miller Field to evaluate brine flow and mixing processes occurring in the reservoir, using an available history matched streamline reservoir simulation model integrated with produced water chemical data. Conservative natural tracers were added into the modelled injection water, and then the displacement of injection water and the behaviours of the produced water in two given production wells were further studied. In addition, the connectivity between producers and injectors was investigated based on the comparison of production behaviour calculated by the reservoir model with produced water chemical data, and an assessment of the properties of the intervening faults was also performed. Finally, a model of BaSO4 scale precipitation was included in the model, and the simulation results with and without barite precipitation were compared with produced water chemical data (observed barium and sulphate concentrations in the produced brine). In general, the modelled and observed data were found to be in good agreement, but any discrepancies were in fact found to be very informative also. The model assumes scale deposition is possible everywhere in the formation, whereas in reality the near production well zones were generally protected by scale inhibitor squeeze treatments, and thus the discrepancies between modelled and observed data could be used to diagnose the effectiveness of the chemical treatments to prevent formation damage around the production wells.
Water flooding has been widely used in the industry as a secondary recovery technique to improve recovery from oil reservoirs. One of the major operational challenges is addressing the compatibility between injected water and formation water in order to proactively lower the probable risk of scale formation near wellbore. A thorough investigation was conducted to evaluate the probability of scale formation and identify the effective mitigation options for a Central Arabian incremental development project.
A holistic approach was implemented at this study to achieve the objective through reviewing analogue reservoirs, running numerical predictions of scale tendency, carrying out laboratory experiments to evaluate the compatibility of the formation water with the injected mix water and conducting in-situ coreflood experiments to quantify the potential risk of formation damage.
This study identified an inherently high calcium sulfate scale risk associated with the planned seawater injection in the new reservoir development and within the surface production fluid process facilities. Appropriate scale mitigation options including the potential impact of an injection seawater sulfate removal process facility will be discussed in this paper.
RS field is located in the Central Arabia and has three oil bearing carbonate reservoirs - two with high-permeability (>100 md) and an underlying low-permeability (average ~ 2 md) one with elongated, north-south trending, asymmetrical anticline structure and a tight aquifer as the lower boundary. Field came on stream in 2009 with production capacity of 1.2 MMBPD and water injection of ~2 MMBWD after initial development of the high-permeability reservoirs. Incremental development project which involves drilling of additional oil producers, power water injectors (PWI) and observation wells is currently planned with part of the production increment expected from the low-permeability reservoir (DL). The new reservoir development is expected to be more challenging than the shallower reservoirs with significantly higher permeability and gross thickness.
Current water injection along the flanks of the field utilizes processed Arabian Gulf seawater (SW) and produced water/disposal water (DW) from the offset reservoirs. Since injection water breakthrough, only minor scaling incidents have been observed in the field with bottom-hole samples of organic and inorganic scales recovered from two wells while logging PLT. Produced water is often used as injection fluid due to the reduced risk of formation damage associated with incompatible fluids since it must be disposed with or without additional clean-up. Mixing waters from different sources exacerbates the risk of scaling. Seawater is obviously the most conveniently abundant source for offshore production facilities, and when pumped inshore for use in land fields. In the absence of non-saline shallow aquifer water which has the greatest advantage of purity, only DW from offset reservoirs and SW from seawater plant were considered for the DL water injection.
Large-scale seawater injection in two high permeability carbonate reservoirs within a remote onshore field commenced with the onset of oil production in early 2000. Following a recent incremental development plan that included an underlying low permeability (2 millidarcies (md)) reservoir with high calcium content (37,000 mg/L) formation water, it became necessary to examine alternative options to the seawater to avoid calcium sulfate scaling and microbial fouling. Secondary treated sewage effluent (TSE) is abundant from nearby urban treatment plants and presents an attractive option for the high-risk divalent ion formation brine environment.
An initial feasibility study focused on geochemical and microbial compatibility to assess the benefits expected from substituting the use of costly desulfated water
The study confirmed that sampled TSE had a relatively low content of contaminants such as oxygen demanding substances (ODS), heavy metals and dissolved solids with minimal formation damage risk compared to both seawater and field produced water. It also revealed variations of total organic carbon (TOC) in TSE, which may enhance troublesome microbial activities and impact the various systems' operational stages
This paper discusses the laboratory experiments and simulation conducted to assess the impact of injection TSE on microbial growth, in situ scale deposition and the associated formation damage risk. It also provides an insight into the effluent quality threshold required for injection in a reservoir of high divalent-salt connate water.