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Al Kalbani, Munther Mohammed (Heriot-Watt University) | Jordan, Myles Martin (Champion X) | Mackay, Eric James (Heriot-Watt University) | Sorbie, Ken Stuart (Heriot-Watt University) | Nghiem, Long X. (Computer Modelling Group Ltd.)
Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the
Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options.
Results show that the
This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.
Al Kalbani, Munther Mohammed (Heriot-Watt University) | Jordan, Myles Martin (Champion X) | Mackay, Eric James (Heriot-Watt University) | Sorbie, Ken Stuart (Heriot-Watt University) | Nghiem, Long X. (Computer Modelling Group Ltd.)
Abstract Mineral scaling issues have been reported in many alkaline and Alkaline-Surfactant-Polymer (ASP) projects. The role of the in situ mineral reactions on the produced scaling ions and pH has been little reported in the literature. The objective of this study is to investigate the impact of the in situ chemical and geochemical interactions on the scale precipitation risk when the fluids reach the wellbore, and their inhibition during Alkaline-Surfactant (AS) and ASP flooding processes. Reservoir simulation is used to model the geochemical interactions and chemical flood flow behaviour using 2D areal and vertical homogeneous and heterogeneous models. Data from the literature is used to model oil, water and rock interactions (interfacial tension, reaction rate parameters, relative permeability, chemical adsorption and polymer viscosity) for surfactant, and sodium carbonate (Na2CO3) and sodium hydroxide (NaOH) alkalis, and HPAM polymer. At the wellbore, squeeze modelling is used to investigate the volume, concentration and cost of calcite scale inhibitor for three different AS and ASP flooding options. Results show that the in situ rock dissolution, mineral precipitation and brine mixing reduce the produced ion concentrations (Ca, Mg, HCO3) and pH compared to the initial concentration and the injected pH value. The calcite scaling risk can be high during Na2CO3 injection while silica and Mg(OH)2 scales are potential minerals that will precipitate in the production system during NaOH injection. Uncertainty in the mineral reaction rate parameters, especially mineral surface area, is important and must be captured, as this may impact the scaling risk in the producer. Among the studied flooding options, ASP with pre and post polymer slugs shortens the calcite scaling period, reduces the scaling ion concentrations and the produced water rates. This case, then, requires the least number of squeeze treatments, the lowest scale inhibitor volume, and delivers the highest incremental oil recovery. This paper gives a workflow for assessing the scaling risks for AS and ASP flooding, with crucial role played by reservoir complexity. It is therefore recommended that scaling assessment calculations following our workflow be carried out for specific AS and ASP field cases.
Al Bahri, Mohammed Said (Heriot-Watt University) | Vazquez, Oscar (Heriot-Watt University) | Beteta, Alan (Heriot-Watt University) | Al Kalbani, Munther Mohammed (Heriot-Watt University) | Mackay, Eric James (Heriot-Watt University)
Abstract It is common that a large volume of hydrocarbons remained unrecovered after primary and secondary recovery. Enhanced Oil Recovery (EOR), as tertiary recovery, plays a key role in recovering additional volumes of hydrocarbons. However, there is little work in the literature on the impact of different EOR mechanisms on the flow behaviour of formation/injected brines and scaling tendencies. The objective of this manuscript is to investigate, by the means of reservoir simulation, the impact of different EOR techniques, namely low salinity waterflooding (LSW), polymer flooding and Thermally Activated Polymer (TAP), for in-depth conformance control, on oil recovery and BaSO4 scale deposition. A reactive transport reservoir simulator was used to evaluate the impact of three EOR techniques in the mixing profiles of injected seawater and formation brine, resulting in the precipitation reaction of BaSO4, due to the incompatible mixing of formation and injected brines. Three two-dimensional models were considered, a homogeneous and heterogeneous areal model to compare polymer flooding and LSW; and a vertical heterogeneous model to analyse the effect of TAP. Results show that LSW delays and reduces the risk of BaSO4 scale deposition at the producer, due to the fact that the concentration of injected SO4 is significantly lower than full sulphate injection seawater. However, LSW results in longer co-production period of Ba and SO4 ions, due to the fact that Ba stripping is reduced because of the scale precipitation within the reservoir is reduced. Polymer flooding improves the sweep displacement, which delays the onset of scale formation, shortens the co-production period of the scaling ions at the producer and reduces the amount of water produced, hence, reducing the scale risk. TAP injection results in the delay of the injected water breakthrough, which delays the onset of scale formation in the producer; however, it can increase the amount of formation water (hence Ba ions concentration), mainly from the low permeability zones, in the producer. EOR techniques may have a major influence on the evolution of scaling ions in the produced water, which has to be taken into account for an optimum scale management strategy, to maximize oil production.
During drilling of a well, the formation is exposed to mud filtrate invasion. The invasion displaces oil in the vicinity of the wellbore, much like a small water flooding experiment in the case of immiscible mud filtrate and formation fluid. Pressure transient or flow test of a wireline formation tester (WFT) commonly provides reservoir properties under the assumption of single-phase flow. However, a WFT sampling operation in a multiphase flow environment gives an opportunity for determining related properties in an inversion workflow by utilizing recorded bottom-hole pressure and water-cut data. In this paper, we present a novel methodology to estimate multiphase flow properties with the help of numerical simulation and optimization.
The numerical simulation model for mud filtrate invasion and cleanup consists of a proper definition of reservoir properties as well as WFT tool geometry, including size and shape of flow inlets, along with tool storage and fluid segregation effects. The model is embedded in an optimization workflow and relative permeability curves, damage skin and depth of mud filtrate invasion are then estimated by minimizing a misfit function between measured and modeled pressures and water-cuts. The relative permeability curves are parameterized using industry accepted models. The optimization workflow uses a distribution function of response parameters where the entire parameter range is included in the numerical runs, thus ensuring that a global optimum is found. Initial parameter estimates for the optimization process are determined from open hole logs, such as resistivity, and from pressure transient analyses.
The methodology developed in this paper is validated by application to a synthetic dataset with a known solution, and it is subsequently demonstrated on actual field data from a sampling job in an oil-water transition zone. The results of this paper demonstrate that it is possible to reliably estimate multiphase flow properties with defined confidence intervals from WFT sampling data. The key contributions of this study are to show the capability of estimating a variety of multiphase flow properties from routine WFT cleanup data and to establish an automated approach, including a novel inversion methodology, to reduce the turnaround time.
A WFT sampling or cleanup operation in a multiphase flow environment gives an opportunity for determining in-situ relative permeabilities and capillary pressures in an inversion workflow by utilizing data recorded downhole. We describe a methodology to estimate multiphase flow properties with the help of numerical simulation and optimization. The numerical simulation model for the mud filtrate invasion and cleanup consists of a proper definition of reservoir properties as well as WFT tool geometry, including size and shape of flow inlets, along with the tool storage and fluid segregation effects. The numerical simulation model mimics the invasion, cleanup and pressure transient events.
Summary Oilfield scale formation represents a significant flow-assurance challenge to the oil and gas industry, because of increasing water production worldwide and higher oil prices. Scale-inhibitor (SI) squeeze treatment is the most widespread method to combat downhole scaling. To predict SI squeeze treatments accurately for further optimization, it is necessary to simulate the SI retention in the formation, which may be described by a pseudoadsorption isotherm. Although these are often derived from coreflood experiments, sometimes they are not appropriate for modeling well treatments because the core tests on which they are based cannot fully represent field-scale processes. In practice, the parameters of an analytic form of the isotherm equation are modified by trial and error by an experienced practitioner until a match is obtained between the prediction and the return profile of the first treatment in the field. The main purpose of this paper is to present a stochastic hill-climbing algorithm for automatic isotherm derivation. The performance of the algorithm was evaluated by use of data from three field cases. Two success criteria were defined: the ability to match a single historical treatment and the ability to predict subsequent successive treatments. To test for the second criterion, a candidate isotherm was derived from the first treatment in a well that was treated with the same chemical package on consecutive occasions, and then the predictions by use of the suggested solution were compared with the observed SI concentration-return profiles from the subsequent treatments. In all the calculations, the performances of both the isotherms suggested by the hill-climbing algorithm and the isotherms derived by trial and error were compared. The results demonstrate that the hill-climbing algorithm is an effective technique for deriving an isotherm for a single treatment, although predictions for successive treatments worsened slightly with each treatment.
Sequestration of carbon dioxide in geological formations has drawn increasing consideration as a potential method to reduce the level of CO 2 in the atmosphere, and therefore mitigate climate change. In particular, saline aquifers can potentially provide a large storage volume worldwide. It is essential to assess the risk involved in storing CO 2 in the subsurface, and simulations of CO 2 injection play an important role. Detailed simulations using a compositional simulator, which solves the equation of state for the fluids and calculates the partitioning of fluids between phases, is time consuming. It is therefore advantageous to use a simpler method for simulation, such as a modification of a black-oil simulator (designed for use in the oil industry), where fluid properties are input using lookup tables.
Abstract Due to the increased cost of scale management in subsea compared to platform or onshore fields, and because of the more limited opportunities for interventions, it is becoming increasingly important to carry out a risk analysis process for scale management as early as possible in the field development plan. A critical part of this process is to evaluate methods of chemical deployment for reservoirs where near wellbore scale has been identified as a significant risk to production - often leading to consideration of the scale squeeze process. This paper discusses how scale squeeze treatment deployment options can be modelled and demonstrates the comparison of mechanical and chemical diversion (particulate or viscosified fluids) with simple rate diversion. In subsea heterogeneous wells diversion via bullhead deployable treatments can be more cost effective than deployment via a rig and coil tubing, provided the treatment distribution is as effective. The ability to model the application process is critical in the economic assessment of coil/rig vs. fix facility deployment in deepwater fields. The paper will outline the process of chemical selection, reservoir/near wellbore modeling and field application for solid, viscosified divertors or deployment options where high pump rates are utilized to achieved better chemical placement. Field treatments where this process has been utilized (North Sea, Brazil and West Africa) will be presented along with the results of these treatments. Practical issues related to overcoming the challenges of subsea flow line cleaning and the effective rates required to achieve diversion are discussed, as are monitoring methods following such treatments to ensure effective placement has been achieved. Introduction Scale Squeeze Process Scale inhibitor squeeze treatments for preventing carbonate and sulphate scales are well-established procedure in onshore and offshore oil production facilities. In general, the squeeze process, comprises pumping a preflush solution (0.1% v/v inhibitor in KCl or injection quality seawater), followed by the selected scale inhibitor (normally in the concentration range of 5% to 20% v/v in KCl or injection quality seawater), and finally an overflush stage (using inhibited seawater or KCl). The well then remains shut-in for a period (6–24 hours) allowing the inhibitor chemical to react with and be retained by the reservoir rock, before the well is flowed back into the test separator and the main process vessels. The function of each stage is described below. Preflush and Spacer Stages This stage is, in its simplest form, designed to displace the tubing and production interval fluids back into the formation. This creates a buffer zone between the formation fluids and the treatment chemicals. This is often desirable due to chemical and produced fluid (oil, brine) compatibility concerns. The preflush stage also reduces the tubing and near wellbore temperature, which reduces the scale inhibitor adsorption rate near the wellbore and reduces the risk of premature precipitation of a treatment designed to phase separate at elevated temperatures. The preflush stage may contain a small concentration (<0.5% v/v) of scale inhibitor along with a small concentration of surfactant or demulsifier to reduce emulsion risk as the produced fluids are displaced back into the formation.
Abstract The most common method for preventing scale formation is by applying scale inhibitor squeeze treatments. In this process, a scale inhibitor solution is injected down a producer well and into the near wellbore formation. Generally, reservoir formations consist of a number of layers or zones of different permeability which may or may not be in pressure communication. When the zones are non-communicating within the reservoir, they are often at different pressures. When this is the case, then this can have a strong influence on the flow and placement of any injected fluids. Indeed, it can dominate the dynamics of the placement process and can also cause wellbore crossflow during the shut-in period following the squeeze treatment. In order to design a successful squeeze treatment, it is very important to know where the injected fluid goes; i.e. where the slug of scale inhibitor is placed in the formation. Therefore, our squeeze design and prediction models must incorporate these layer pressure effects along with the other models for the scale inhibitor transport and retention mechanisms. In this paper, we develop the analytical expressions for calculating the flow partition in radial layered formations, where the layers are non-communicating. This is not in itself original and these equations are "well known". However, we have incorporated them into our multi-layer, two phase scale squeeze design software (SQUEEZE VI) to simulate situations where layers are at different pressures. We demonstrate that this has an important effect on the scale inhibitor slug placement in a heterogeneous system and it drives crossflow between layers at production or injection stages. Furthermore, we go on to show what the consequences of these placement effects on the squeeze lifetime are. We also present a wide sensitivity study of this effect showing how a number of ancillary parameters affect the squeeze lifetime e.g. the magnitude of the differential pressure between layers, the permeability contrast, the retention mechanism. Finally, we give some general field guidelines for various specific situations where formation zone pressures are not equal in terms of squeeze applications. Introduction Chemical scale inhibitors (SI) have been used very extensively in field applications to prevent scale formation in production wells. In most cases, scale inhibitors are injected into the formation as an aqueous solution during a "squeeze" treatment, where they will be retained on the rock grain surfaces and will gradually flow back into the production wells as they desorb/dissolve off the rock. Scale inhibitors are normally effective above a certain concentration, commonly known as the minimum inhibitor concentration (MIC). The squeeze treatment lifetime is determined by the length of time that it takes (or volume of treated brine produced) before the SI return concentration declines below MIC. In a single homogeneous layer formation, the squeeze lifetime is principally determined by the physical interaction of SI and the rock formation. However, frequently wells are drilled and completed in multiple heterogeneous rock layers. In this study, we will only consider formations composed of a number of non-communicating layers, characterized by permeability, porosity and height (completion interval), where each layer may be at different pressures before the squeeze treatment is deployed. In such scenarios, SI placement in each layer will be significantly affected by the respective layer pressures. This may, in turn, have a significant impact on the SI return concentration profile. Seright and co-workers derived analytical expressions to calculate flows and relative penetrations of injected fluid in both linear and radial heterogeneous formations with no-crossflow, assuming that all the layers were at the same pressure. Other investigators studied the flow patterns in layered and unlayered formations with crossflow. Zhang and Sorbie implemented a mathematical model in SQUEEZE V to calculate the single phase flow partitioning in layered formations, based on the permeability height product of each layer. Latterly, analytical expressions for multilayered systems in two phase flow with no crossflow have been applied to squeeze treatments, assuming that the all the layers were at the same pressure.
Abstract The most common method for preventing scale formation is by applying a scale inhibitor squeeze treatment. In this process, a scale inhibitor solution is injected down a producer well into the near wellbore formation. Commonly, scale treatments comprise the following stages: preflush, main scale inhibitor pill, overflush tubing displacement and shut-in, followed by back-production of the well. For some years the industry has applied mutual solvent chemicals in the preflush stage of such treatments to (i) avoid emulsion formation or water blocking, thus avoiding slow well clean-up, and also (ii) for enhancing adsorption of the scale inhibitor onto the formation rock. This paper discusses the effect of a mutual solvent preflush on scale inhibitor squeeze lifetime and also on well clean up time. It builds on a previous publication that introduced a recent model to simulate the impact of a surfactant on improved inhibitor retention, which used data derived from laboratory experiments. The focus of this paper will be to consider the impact of the mutual solvent on well clean up time and the model is used to demonstrate the effect of a mutual solvent in quickly bringing wells back to full oil production. A field example is presented for a deepwater field in West Africa where intervention costs are high and any negative impact of squeeze treatments can have a significant associated deferred oil cost. A scale inhibitor squeeze design in which a mutual solvent is deployed in the preflush should account for the following phenomena: mutual solvent propagation, diminishing mutual solvent efficiency due to interaction with the fluid phases, impact of the mutual solvent on scale inhibitor retention due to increased rock surface area available for adsorption, and impact of mutual solvent on saturation dependent relative permeability functions and phase mobilities. These aspects are discussed in the paper, and the model is used to demonstrate their impact on a squeeze treatment. Particular attention is paid to the reservoir wettability, and the importance of the shape of the relative permeability curves in determining the clean up time for a well, and the benefit that a mutual solvent may bring in overcoming slow clean up times. The model is then used to demonstrate how the preflush stage of given specific field squeeze designs may be adapted to ensure optimum efficiency in terms of chemical usage, minimised deferred oil production and extended squeeze life. Introduction Precipitation of inorganic mineral scale in producing wells is one of the biggest production challenges of the oil and gas industry as oil reservoirs are becoming more mature and watercuts are increasing. The most common scales are carbonates, caused mainly by CaCO3 precipitation (due to reservoir pressure depletion), and sulphate scales, created by the incompatible mixing of reservoir brine and injected water (normally seawater). Scaling is present in all the producing areas of the world; however, the severity of the scaling tendency varies from field to field, as does the degree of difficulty managing the problem from relatively simple low temperature low pressure vertical platforms wells to high temperature and pressure, where compatibility and thermal stability are major concerns, carbonate reservoirs where the precipitation of pseudo scales may cause formation damage and complex deep seawater completions.
Abstract Waterflooding is a very common method of oil displacement and pressure support. One particular problem that may arise after injection water (IW) breakthrough at the production well is the formation of sulphate scale. One of the main parameters that determines the severity of this type of scale formation is the amount of injection water/formation water (IW/FW) mixing that has taken place. Thus, the injected water fraction in the produced brine mix is an important value to determine. Our ability to model scale precipitation in situ and in the well is linked to our ability to accurately determine the IW fraction at production wells. Current industry practice is to work on an analytic approach for determining the fraction of IW in the produced brine stream in general, and for identifying IW breakthrough in particular. A robust and accurate method for determining IW fraction in field produced water analysis is required to match the modelled IW fractions. When this is achieved, it is possible to use various modelling techniques with a higher degree of confidence to predict future scaling tendencies, and to help implement an appropriate scale management strategy to economically mitigate the potential effects of scale damage. In this paper, the "Reacting Ions" method is introduced for determining the fraction of IW (and FW) in produced waters. This method is then applied to a synthetic produced water case where the "correct" answer is known, and a very good match is achieved, even when significant noise is applied to the synthetic data. The method is then applied in the analysis of produced brines for several wells in a North Sea field. Results of the study presented here show that the method is more effective in detecting IW fractions than conventional ion tracking techniques, especially at low IW fractions close to when breakthrough occurs. The significant new development presented in this work is that this approach may be used accurately even in situations where scale deposition deep in the reservoir impacts the concentrations of the ions used in this method. Introduction Water is a universally occurring natural solvent in all sedimentary systems where petroleum is found. In contact with rocks, water may dissolve minerals in the matrix, and so subsurface waters are usually solutions containing a wide variety of ions, including Na, Ca, Mg, Cl, etc. The properties which may be used to characterise subsurface brines include temperature, chemical composition, pH, amount of total dissolved solids (TDS) and resistivity. Waters held in deep formations over geological timescales are often referred to as formation water (FW). The properties of subsurface waters vary significantly from one reservoir to another. The chemical compositions may range from relatively fresh waters, evaporated sea water or to highly concentrated brines. Hydrocarbons in reservoirs are coupled with subsurface waters which in turn play an important role in the original hydrocarbon migration and accumulation. Water deep in reservoirs can be present as a result of trapping during sedimentation or filtration, or a combination of both mechanisms (Ostroff, 1975). Over geological timescales, the subsurface waters come into chemical equilibrium with the rock and the hydrocarbons. In the oil industry, waterflooding is a widely applied secondary recovery method. During a waterflood, injection water (IW) is pumped into injection wells into the reservoir to displace mobile oil towards the production wells, and to provide energy to lift hydrocarbons to the surface (Dake, 1978; Craig, 1980; Willhite, 1986; Lake 1989). During water injection, subsurface formation waters (FW) are displaced along with the hydrocarbons, and are often produced in a IW/FW mixture that may contain a range of cations and anions as well as rock particles, sand, hydrocarbons drops, etc. The amount of produced water from a production well (and from an entire reservoir) generally increases with time.