The objective of this work is to characterize the fault system and its impact on Mishrif reservoir capacity in the West Quran oil field. Determination and modelling of these faults are crucial to evaluate and understanding fluid flow of both oil and water injection in terms of distribution and the movement. In addition to define the structure away from the well control and understanding the evolution of West Qurna arch over geologic time.
In order to achieve the aim of the work and the structural analysis, a step wise approach was undertaken. Primarily, intensive seismic interpretation and building of structure maps were carried out across the high resolution of 3D-seismic survey with focusing on the main producing Mishrif reservoir of the field. Also, seismic attributes volumes provided a good information about the distribution and geometry of faults in Mishrif reservoir. The next step, it constructs 3-D fault model which will be later merged into the developed 3D geological model. West Qurna/1 oil field situated within the Zubair Subzone, and it is structurally a part of large anticline towards the north. The observation of seismically derived faults near Mishrif reservoir indicated en-echelon faults which refer to strike-slip tectonics along with extensional faults. The statistic of Mishrif interval faulting indicates a big number faults striking north-south along western wedge of anticline. The seismic interpretation, in combination with seismic attributes volumes, deliver a valuable structural framework which in turns used to build a better geological model.
In this paper, the work demonstrates a better understanding for the perspectives on the seismic characterization of the structural framework in the Mishrif reservoir, and also for similar heterogeneous carbonate reservoirs. Further, this work will ultimately lead to improve reservoir management practises in terms of production performance and water flooding plan.
As an enhanced oil recovery method (EOR), chemical flooding has been implemented intensively for some years. Low Salinity WaterFlooding (LSWF) is a method that has become increasingly attractive. The prediction of reservoir behaviour can be made through numerical simulations and greatly helps with field management decisions. Simulations can be costly to run however and also incur numerical errors. Historically, analytical solutions were developed for the flow equations for waterflooding conditions, particularly for non-communicating strata. These have not yet been extended to chemical flooding which we do here, particularly for LSWF. Dispersion effects within layers also affect these solutions and we include these in this work.
Using fractional flow theory, we derive a mathematical solution to the flow equations for a set of layers to predict fluid flow and solute transport. Analytical solutions tell us the location of the lead (formation) waterfront in each layer. Previously, we developed a correction to this to include the effects of numerical and physical dispersion, based on one dimensional models. We used a similar correction to predict the location of the second waterfront in each layer which is induced by the chemical's effect on mobility. In this work we show that in multiple non-communicating layers, material balance can be used to deduce the inter-layer relationships of the various fronts that form. This is based on similar analysis developed for waterflooding although the calculations are more complex because of the development of multiple fronts.
The result is a predictive tool that we compare to numerical simulations and the precision is very good. Layers with contrasting petrophysical properties and wettability are considered. We also investigate the relationship between the fractional flow, effective salinity range, salinity dispersion and salinity retardation.
This work allows us to predict fluids and solute behaviour in reservoirs with non-communicating strata without running a simulator. The recovery factor and vertical sweeping efficiency are also very predictable. This helps us to upscale LSWF by deriving pseudo relative permeability based on our extension of fractional flow and solute transport into such 2D systems.
The objective of this work is to characterize the porosity distribution and the types of carbonate facies in the Mishrif Formation in the West Qurna/1 Oil Field using seismic inversion results, well log data and rock physics modeling. Identification of the pore system and the spatial distribution of lithofacies are keys for constructing Mishrif reservoir model, which have a great impact on the development of the most prolific reservoir in the field (Mishrif zone).
Seismic inversion involves the interpretation of elastic properties for facies based on the seismic response. It enables the modelling of lithology and porosity distribution in 3D space away from well control. In order to achieve the aim of the work, a step wise approach will be taken. First of all, deterministic seismic inversion was applied across the high resolution of 3D-seismic survey data over the West Qurna/1 Field. Then, the vertical distribution of porosity and facies recognition based on well log data and its relationship with elastic properties, integrated with seismic inversion results for validating at Mishrif intervals.
Deterministic seismic inversion was undertaken on the post-stack seismic dataset. The interpretation of seismically derived characterization in Mishrif reservoir indicated a different lateral distribution of acoustic impedance and three regions of channel (north, southwest and east). It can be seen a high acoustic impedance anomaly outside the channel in the western field sector which is heavily mud supported by peritidal carbonates (low quality facies of the reservoir). Whereas, carbonate tidal channel displayed a low acoustic impedance which reflect high porosity and good reservoir quality (grainstone channel or sholas). Furthermore, the interpretation of the well log and rock physic model was correlated with seismic inversion volume in terms of the lithology and porosity. Consequently, some zones which included carbonate tidal channel, displays a wide range of porosity and lithology fluctuations due to the impact of depositional environment (subaerial exposure).
The workflow provided insight into the distribution of petro-physical properties and quantification of their influence on dynamic reservoir behavior. The results also indicated the areas of high permeability and its component that may include fractures or connected vug systems. Water flood design and completion strategies (well trajectories) will be developed and succeeded according to the heterogeneous geological regions. Overall, this will ultimately lead to improve the development plan of wells in terms of production performance, recoverable reserves and economic value.
Hydraulic fracturing stimulation is considered a successful development technique in tight gas reservoirs. However, these expensive operations sometime underperform due to ineffective fracture fluid (FF) clean-up. This paper concentrates on FF clean-up efficiency for a Multiple Fractured Horizontal Well (MFHW) completed in both homogeneous and naturally fractured (NF) tight gas reservoirs. The emphasis is on NF reservoirs that make up a large percentage of tight gas assets, as their clean-up efficiency has received little attention.
In this study, two numerical simulation models, i.e. a single-porosity single-permeability and a dual porosity-dual permeability model representing a homogeneous and a NF tight gas reservoir respectively, were used. Simulations were conducted on a MFHW with seven hydraulic fractures (HF). The process comprised of injection of FF, then a soaking time (ST) followed by production. The impact of various parameters which includes ST, FF viscosity, pressure drawdown and parameters pertinent to relative permeability and capillary pressure in matrix, hydraulic and natural fractures, were evaluated.
In addition, based on a newly proposed treatment process that generates in-situ pressure and thermal energy that breaks gel viscosity, the effect of resultant viscosity reduction and local pressure increase, for improving the clean-up efficiency was also assessed. In these simulations, and due to uncertainty in its value, NF permeability was varied over a wide range. For conclusive purposes, Gas Production Loss i.e. GPL (%) defined as the difference in total gas production between the completely clean and un-clean cases as a percentage of the clean case, after a specific production period was used. This paper prioritizes the impact of pertinent parameters and highlights the influence of thermochemicals on the clean-up efficiency thereby justifying its commercial practicality. For instance, it is shown that the presence of NFs results initially in higher GPL but then GPL reduces significantly. Reducing the FF viscosity improves clean-up significantly especially for the NF models as NFs are the main contributor to the gas and FF flow from the reservoir to surface via hydraulic fractures. The sometimes non- monotonic trend of GPL variations, depends on the specific combination of NFs’ permeability and FF viscosity which results in the certain fluid invasion profile and mobility in the system.
The paper emphasis is on the impact of thermochemicals and natural fractures on the cleanup up efficiency of hydraulic fracturing stimulations that should be optimized to reduce cost, thereby increasing the profit from these projects.
Numerical stability and precision are required when using simulations to predict Enhanced Oil Recovery processes and these can be difficult to achieve for Low Salinity Water Flooding (LSWF). In this paper we investigate the conditions that lead to numerical instabilities when simulating LSWF. We also examine how to achieve more precise simulation results by upscaling the flow behaviour in an effective manner.
An implicit finite difference numerical solver was used to simulate LSWF. The stability and precision of the numerical solution has been examined as a function of changing the grid size and time step. We used the Peclet number to characterise numerical dispersion with these changes. Time step length was compared with the Courant condition. We also investigated some of the nonlinear elements of the simulation model such as the differences between the concentrations of connate water salinity and the injected brine, effective salinity concentration range and the net mobility change on fluids through changing the salt concentration.
We observe that numerical solution of LSWF tends to be conditionally stable, with problems occurring as a function of the range of effective salinity concentration relative to the initial reservoir water and the injected brine concentrations. We observe that the Courant condition is necessary but not sufficient. By definition, the precision of the numerical solution decreased when increasing numerical dispersion but this also resulted in slowing down the low salinity water and increased the velocity of the formation water further reducing precision. These numerical problems mainly depend on fluid mobility as a function of salt concentration. We conclude that the total range and the mid-concentration of effective salinity affect the stability and precision of the numerical solution, respectively. In this work, we have developed two approaches that can be used to upscale simulations of LSWF and tackle the numerical instability problems. The first method is based on a mathematical form that gives the relationship between the fractional flow, effective salinity concentration and the Peclet number. The second method is that we have established an unconventional proxy method that can be used to imitiate pseudo relative permeabilities.
This work enables us for the first time to simulate LSWF by using a single table of pseudo relative permeability data, instead of two tables as traditionally done in previous studies. This removes the need for relative permeability interpolation during the simulation and will help engineers to more efficiently and accurately assess the potential for improving oil recovery using LSWF and optimise the value of the field development. We also avoid the numerical instabilities inherent in the traditional LSWF model.
Low Salinity Water Flooding (LSWF) is an emergent technology developed to increase oil recovery. Many laboratory tests of LSWF have been carried out since the 1990's, but modelling at the reservoir scale is less well reported. Various descriptions of the functional relationship between salt concentration and relative permeability have been presented in the literature, as have the differences in the effective salinity range over which salt content takes effect. This paper focuses on these properties and their impact on the fractional flow of LSWF. We present observations that help characterise the flow behaviour in a more general form, simplifying the interpretation of results. We explain how numerical or physical diffusion of salt affects the velocity of the waterflood front, and how this can be predicted from fractional flow analysis.
We have considered various linear and non-linear shapes of the function relating salinity to relative permeability and different effective salinity ranges using a numerical simulator applied at the reservoir scale. The results are compared to fractional flow theory in which both salt and water movement is assumed to be shock-like in nature.
We observe that diffusion of the salt front is an important process that affects the fractional flow behaviour depending on the effective salinity range. The simulator solution matches the analytical predictions from fractional flow analysis under the condition that the mid-point of the effective salinity range is at the mid-point between the formation and injected salt concentrations. However, an effective behaviour similar to adsorption/desorption occurs when these mid-point concentrations are not coincidental. The outcome is that the fronts representing high and low salinity water travel with altered velocities and at different saturations.
We find that we can predict this behaviour from the input data alone as an augmented form of the fractional flow theory including the concept of retardation or acceleration as occurs for adsorption and desorption for other injectants. We use the analytical solution to the advection-diffusion equation and find that the changes in behaviour depends on the Peclet number.
The result of our work is that we have produced an updated form of the fractional flow model of LSWF, to include the impact of salt front diffusion on the movement of fluids. A new factor is introduced, similar to adsorption in polymer flooding. We have developed a new mathematical formula, empirically, to estimate the magnitude of this factor. The new form can be used to modify the effects that numerical or physical diffusion have on the breakthrough times of high and low salinity water fronts during LSFW. This will improve predictive ability and also reduce the requirement for full simulation.
This study assessed the impact of static and dynamic variables in EUR and NPV in the development plan of a North Sea offshore field with 81 m of water, light oil crude of 40.5 API and 510 SCF/STB of GOR comprised of sandstones from a shallow marine environment in anticline structure separated to the northeast and southwest by a pair of normal faults. The analysis is conducted through the application of different experimental design techniques and the preparation of a comparison between them. Uncertainty analysis has been prepared to characterize the appropriate range for nine variables that affect the oil recovery and net present value of the field development. A Folded Plackett-Burman design was prepared to screen the initial nine variables; the linear regression results show that the oil water contact, permeability anisotropy and net to gross are the significant variables. Also, the residual analysis demonstrated that the proxy equation should be improved to have better predictability in the non-sampled space. In consequence, a D-Optimal and a Central Composite experimental design were prepared for the three significant variables. The regression results show better coefficient correlation and lower least square errors in the D-Optimal design using a full quadratic model and confirmed the oil water contact as the most significant variable of the field. Finally, Monte Carlo Simulation was performed in the proxy model from the D-Optimal design, which resulted in an expected value ultimate recovery of 357 MMSTB. The paper presents an exciting workflow to analyze different experimental design techniques, compare them and use the most suitable to prepare the development plan of a field.
Scale inhibitor squeeze treatments are used to prevent scale deposition in production wells. A treatment consists of injecting a scale inhibitor slug at a concentration between 5 and 15%, referred to as the main treatment, followed by an overflush, which will push the chemical slug deeper into the reservoir. During injection, the stages might undergo some degree of mixing in the tubing. This paper addresses the impact such mixing would have on the squeeze lifetime. A consequence of mixing between main treatment and overflush stages in the well tubing would be that although the same overall mass of scale inhibitor was injected, it would be distributed over a larger volume of water and therefore be exposed to the rock formation at a lower concentration than planned in the design. The degree of mixing in the tubing depends on a number of factors, such as tubing length and diameter, and the pumping rate. The phenomenon is described by the longitudinal dispersion coefficient, which may be calculated.
The resulting calculation may be defined as the spreading of a solute along the longitudinal axis, which leads to the spread of an initial high concentration slug with a low spatial variance to a final stage of low concentration with high spatial variance. The main objective of the paper is to study the effect of the degree of mixing of the main and overflush stages on the squeeze treatment lifetime. The net effect of full mixing would be that instead of there being two different stages at very different scale inhibitor concentration, a single stage at a lower concentration might be exposed to the rock formation. Two mixing profiles were considered, a short and long tubing; where the total injected volume is greater than and less than the total tubing volume, respectively. A number of levels of mixing were considered and compared to the base case, where no mixing was allowed. The results showed that squeeze lifetime is not significantly reduced if mixing occurs in a short tubing interval, whereas it can be reduced by up to 20% in a longer tubing interval.
Iron sulphide (FeS), zinc sulphide (ZnS) and lead sulphide (PbS) are considered to be among the most challenging scales in terms of inhibition and removal. They can form by direct reaction of aqueous sulphide species with dissolved Fe, Zn and/or Pb and by the exchange between aqueous sulphide species with preformed iron compounds, such as iron oxide hydroxide. These existing iron compounds may have formed during production and/or intervention, such as an acid treatment. Similarly, PbS and ZnS can form by extracting sulphide from a more soluble sulphide scale
The majority of this study was conducted under anaerobic conditions, with the scale formation and/or inhibition experiments being monitored by inductively coupled plasma (ICP) analysis, pH and particle size measurements. Among the tested scale inhibitors, two showed high efficiency against iron sulphide, however high pH and salinity had a detrimental impact on the performance of one of these products. Interestingly, these scale inhibitors prevented iron sulphide deposition even under aerobic conditions
The particle sizes of inhibited (suspended) FeS were significantly lower than the blank FeS samples, with this effect increasing with increased scale inhibitor concentration. This difference in particle size may have an important influence on in-line filter blocking tests and produced water quality issues.
The deposition of carbonate and sulphate scales is a major problem during oil and gas production. Managing scale with chemical application methods involving either scale prevention and/or removal are the preferred methods of maintaining well production. However, chemical scale control is not always an option, depending upon the nature of the reservoir and well completion and, in cases of severe scaling, the problem can render chemical treatments uneconomic unless other non-chemical methods are utilised.
A variety of non-chemical scale control methods exist, the most common being injection of low salinity brines or low sulphate seawater (LSSW) using reverse osmosis and a sulphate removal plant (SRP) respectively. In addition, careful mixing of lift gas, produced waters and reinjection, coatings, smart well completions with active inflow control devices (ICD) and sliding sleeves (SS) are other methods.
All of these techniques, including combinations thereof, are currently in use and the advantages and disadvantages of the key techniques are compared to chemical methods for both carbonate and sulphate scale control. A detailed example from a North Sea field demonstrates where downhole chemical scale control has not been required through a strategy of careful mixing of lift gas, brines and produced water re-injection. This was combined with understanding fluid flow paths in the reservoir and their likely breakthrough at production wells.
Consideration is given to the injection of smart brines to scale deep in the reservoir, and data from North Sea chalk fields shows how "
This paper presents a comprehensive review of non-chemical methods for downhole scale control and discusses how the use of these techniques can provide alternative scale management strategies through minimising or alleviating the need for downhole chemical treatments.