Scanning electron microscopy (SEM), X-RAY diffraction (XRD) and X-RAY Fluorescence (XRF) were employed to investigate the silicate scale during alkaline flooding. The formation of silicate scale is a multi-step process, involving silica dissolution, silica polymerization, and precipitation with other ions. It is a massive headache burdened to the oil and gas industry today. The aim of this study is to come out with a static model based on series of experiments to investigate the silicate dissolution ratio using quartz sand core samples. Synthetic brine with different salinities ranged from 5,000 ppm to 60,000 ppm and different alkali concentrations ranged from 0.4% to 1.2% were utilized to determine the change in soluble silica concentrations. In addition, two inhibitors; namely, Boric acid (BA) and Ploy Acrylic Acid (PAA) were screened and the optimum concentration for each inhibitor was identified. Based on the results from this experimental work, the silica dissolution ratio increased significantly with the increase in the the alkali concentration. The silica dissolution ratio increased from 1.1% at 0.4% alkali concentration to 4.6% with alkali concentration of 1.2 %. By introducing BA and PAA as inhibitors separately, significant improvement was observed in both cases. Using 50 mg/l of BA and PAA, 3.1% and 11.2% of the dissolved silica was inhibited, respectively. However, only 37.2% was inhibited when the BA concentration was increased to 350 mg/l, while 72% of the dissolved silica was inhibited when 350mg/l of PAA was utilized. The outcome from this research indicates that the best inhibitor does not prevent the silicate scale, but it might reduce it. This study may assist in understanding the mechanism of silica dissolution process and its effect against alkaline flooding.
Silica is a general term, which refers to silicon dioxide in all of its crystalline, amorphous, and hydrated or hydroxylated forms. It commonly implies that the silicon content is given in terms of weight of silicon dioxide (SiO2). Silicate scale is one of the major formation damage problems during EOR operations, especially chemical and thermal flooding, (Bremere et al., 2000).
Chemical flooding in sandstone reservoir is associated with silicate scaling in production wells. These wells require numerous workovers. Mineral scale inhibitors are generally ineffective at treating silicate scale in these wells (Joseph et al., 2011). Alkali is one of the most important chemicals that have high impact on the silicate scale.
Strong alkali (NaOH, KOH, NaSiO4) are very effective for mobilizing residual oil in laboratory scale, but implies also higher reactivity effects with reservoir rocks (clays, basically kaolinite), leading to chemical consumption and precipitation of alumino-silicates, and thus leading to a decrease in the value of permeability (Patino et al. 2003).
Numerous studies (Sonne et al. 2012, Joseph et al 2010, Konstantinos et al., 2008, Amjad 2008, Smith 1998, Gill 1998, Krumrine et al., 1984) were declared that the formation silicate scale is a highly complex process caused as a result of silica dissolution, its polymerization and precipitation with other multivalent ions. The type of silica-containing scale, silica rate and quantity are dependent on several factors; however the important three factors that have remarkable effect are pH, ion concentrations, and temperature. The silica does not merely dissolve in water, but is solubilised through the hydrolysis reactions. The dissolving of silica depends on pH, i.e. the amorphous silica in the solution at pH in range of 6-8 is in form of un-dissociated H4SiO4 (silicic acid); therefore the dissolving of silica at pH 7 is represented as given in the below reaction (Azizi 2001, Southwick 1984).
Much has been written about carbonate reservoir complexities, heterogeneity, and data integration at different scales. However, there are not many published examples that show a comparison of producibility modeling predictions and actual field results that include data from core, advanced openhole well logs, formation testers, and drillstem tests.
In this study, we present the integration of data and measurements from advanced technologies to evaluate reservoir heterogeneity of carbonate formations on multiple scales. Quantitative textural analyses based on a comprehensive suite of petrophysical logging measurements were integrated with core data and formation testing data to characterize hydrocarbon/water transition zones and formation permeability and producibility. The offshore carbonate reservoir studied is composed of limestones and dolomites. Despite the inherent chemical complexities and hidden modes of origin, dolomites often exhibit favorable reservoir quality with high porosity and permeability properties. For this reason, E&P companies continue to predict where drilling targets are most likely to encounter these sweet spots.
Traditional permeability correlations are not effective in these systems, leading to overdependence on porosity-based reservoir descriptions to predict fluid flow. Using nonparametric regression, we have established a relationship between permeability and porosity from logs that are available fieldwide. Subsequent integration of this data with interval pressure transient test data in zones selected based on the observed rock heterogeneity enables further optimization of the final permeability correlation. The descriptions of the field examples confirm the success of this integrated approach and include the planning, real-time monitoring, and final validation of permeability and anisotropy at different scale during the exploration phase of a field.
Selecting the well locations for development using the proposed approach has proved valuable for improving field development practices. The results have led to enhanced reservoir characterization based on flow (permeability) and storage-capacity analyses (porosity partitioning), and a better understanding of the reservoir heterogeneity at different scales; the results have been used to improve drillstem test designs and reservoir production strategies.
Petrophysical analysis of carbonate reservoirs can prove challenging for a variety of reasons. All aspects of evaluation—whether mineralogy, porosity, permeability, rock types, saturation, relative permeability, or capillary pressures (Elshahawi et al. 2000)—can pose unique challenges, and techniques that work well in siliciclastic reservoirs often fail in carbonates. To achieve the maximum potential of the well or the reservoir, one must understand the carbonate rock formation along the wellbore and reservoir boundaries. Therefore, a quantitative textural analysis based on a comprehensive suite of petrophysical logs, core data, and data from advanced formation testing technologies will help E&P companies to meet the specific challenges and optimally drill, produce, and develop these reservoirs.
Brazil has a huge sedimentary area, covering more than 6,000,000 km2 in onshore and offshore basins. On a geological timescale, the carbonate rocks vary from the Precambrian to Quaternary age. Despite their abundance, they comprise less than 4% of the proved hydrocarbon reserves in Brazil (Spadini 2008), mainly because of their varying reservoir quality.
In this paper it is proposed a workflow to characterize the reservoir at different scales to support the decisions behind vertical and horizontal well placement, well completion and testing this kind of reservoir. Almost ten wells were drilled in the studied area following this reservoir characterization workflow but only three of them are presented in this article; the first vertical drilled well (Well A), a slightly deviated well (Well B) that was the pilot for a sidetrack horizontal well (Well C).
In Egypt's Western Desert, water saturation evaluation of the Upper Bahariya reservoirs is complicated by significant uncertainties in the resistivity-based saturation equation inputs, mainly the formation water salinity, but also the cementation factor and the clay cation exchange capacity (CEC).
A novel dielectric multifrequency measurement was able to clearly identify zones in which oil was present, regardless of these inputs. It provided a residual oil saturation and clear differentiation of oil-bearing zones from water-saturated zones. The measurement also permitted us to apply constraints to the conventional saturation interpretation from shallow and deep resistivities. This process highlighted the variability of formation water salinity across the well and the mixing of filtrate and formation waters in the zone investigated by microresistivity tools.
The dielectric tool also measures dielectric dispersion, from which a parameter (MN) related to the tortuosity of the conduction path can be extracted. This MN parameter was used to refine the water saturation computation from deep-resistivity logs. Variation of the MN parameter between 1.8 and 2 was observed in the reservoir zones. In the zone of interest, a water saturation difference of 7-8 % was observed in the cleanest zone between water saturation computed using the variable MN parameter and that computed using a fixed cementation factor of 1.9. The water saturation recomputed using the data from the dielectric log matches well the irreducible water computed from the nuclear magnetic resonance (NMR) data.
Dielectric dispersion was also used to derive the CEC, which was then input as a direct measure of shaliness in the deep-resistivity saturation equation.
The dielectric measurement increased the accuracy of the water saturation computation in this challenging environment and provided data that are not directly available with conventional logging.
This case study focuses on the Upper Bahariya formation, in Egypt's Western desert, a complex, thin-bedded sequence developed in a tidal flat environment (marine silts and shales) with crosscutting channel sands. The evaluation process in this formation is challenging because of the thin layers and the low-resistivity pay that is due to a combination of laminations and conductive clay minerals. In the field of interest, another major challenge was the variation of formation-water salinity. It had been observed from formation water samples that formation water was getting fresher with increasing depth. But discrepancies had been observed in the water salinity values measured from the downhole samples, and it was not possible to build a model that would account for the variations. These uncertainties translated into uncertainties in the water saturation evaluation.
The acquisition of dielectric data was proposed to obtain a salinity-independent flushed-zone water saturation evaluation. This paper describes the results of applying this technique to the Upper Bahariya formation.
Deposition of sulfur as a solid phase will result in plugging the pore space available for gas flow and reduce the reservoir productivity. For the isothermal conditions in the reservoir, the reduction in reservoir pressure below a critical value will cause the elemental sulfur to deposit in the formation. Sulfur deposition can cause severe loss in the pore space available for gas, and in will affect the gas well productivity.
In this paper a new analytical was developed to predict the effect of sulfur deposition on the damage of the near-wellbore. The damage will be quantified through the investigation of the effect of sulfur deposition on the reservoir porosity, permeability, relative permeability, and the change in rock wettability due to sulfur deposition especially in the near-wellbore region. The developed model considered the change in reservoir gas properties with the change in reservoir pressure which has been neglected by previous investigators. The main objective of these models is to investigate the effect of radial distance on formation damage. Different rock and fluid properties accurate correlation were used in this model for better results prediction. Coreflood experiment was performed to determine the effect of sulfur deposition on the carbonate rock permeability, porosity, and wettability. The experiment was used to determine the effect of sulfur adsorption on the rock petrophysical properties.
Model predictions showed that sulfur deposition depends on the radial distance from the well bore. The analytical model can be used to predict the sulfur deposition in the near-wellbore region. Sulfur deposition was found to have a great effect on the rock wettability, and in turn the gas production will be affected. It was confirmed experimentally that the sulfur deposition reduced the carbonate core porosity, permeability, and changed the contact angle. The contact angle increased which means sulfur adsorption on the rock surfaces changed the rock towards more gas wet rock.
Deposition of a liquid sulfur phase in the reservoir will not significantly plug the pores in the formation if it was a mobile phase. But if the sulfur was deposited as a solid phase, it will result in plugging the pore space available for gas flow and will reduce the reservoir productivity index to a great extent (Mei et al. 2006).
An early concern of many problems associated with sulfur deposition during production of sour gas wells has been documented. Kuo and Colsmann (1966) developed a mathematical model of a solid phase precipitation in a porous medium and its effect on the fluid flow in porous media. The results of this model showed a rapid buildup of solid sulfur around the well and significant depositions near the wellbore due to the depletion of the reservoir pressure.
As stated by Hyne (1968) in his survey of more than 100 producing sour gas wells in Canada and Europe, there was sulfur deposition at the bottom of the producing wells. Hyne stated that, high bottom hole and wellhead temperatures and low wellhead pressures provide favorable conditions for sulfur deposition in the tubing.
Experimental studies were done using core samples to investigate sulfur deposition in the reservoir rock. Al-Awadhy et al. (1998) conducted a core flow experiment to study the sulfur deposition in carbonate oil reservoirs. They used actual crude oil and a carbonate core sample. The experiment indicated an increase in the differential pressure across the core and decrease in permeability due sulfur deposition under different flow rates. Also they stated that the flow impairment due to sulfur deposition in the vicinity of wellbore is the most severe when sulfur deposits as a solid phase. The deposition of the immobile phase can completely plug the formation.
Meleiha North East oil Field is located in the Egyptian Western Desert. Its estimated value for the OIIP is 125.5 MMSTBO. The field started production in the year 1986 and was subjected to 4 years of natural depletion. The reservoir mainly consists of three producing layers; all are heterogeneous with local poor horizontal connectivity and low natural pressure support. Consequently, and during that period of natural depletion, the recovery of only 14.7 MMSTBO caused the reservoir pressure to decline from an initial value of 2300 Psi to 1000 Psi; a slope of approximately (-325 Psi/year). After applying water-injection in the year 1990, the pressure decline-slope got reduced to (-30 Psi/year). Currently the field contains 27 producers and 3 injectors. The distance to the nearest water-source well is approximately 10 Kilometers.
Maintaining continuous injection remained a challenge due to the typically associated operational problems; the long length of the injection lines increased the frequency of line leakage, corrosion, and blockage. Both water-source and injection wells require regular maintenance operations to handle problems such as casing leaks and ESP's maintenance. The necessity of flushing the injection lines after each operation results in additional time losses. Other problems maybe related to issues with the injection plant. All of these operational difficulties eventually affect the reservoir pressure performance and consequently decrease the production performance.
A technological revolution is going on in almost every sphere of modern life which is being possible due to regular and systematic innovations. In spite of this fact, there are few areas where there is no innovation or improvement in the system. Multiple zone well completion technology is one of such area. Over 100 years back, professionals started to develop an effective and efficient multiple zone well completion technology. But the dream of producing multiple zones encountered in a well, simultaneously, without causing inter well cross flow, remained a distant reality. This has not only resulted in poor productivity per well but has also created a bottleneck in the application of advanced technologies for secondary and tertiary recovery methods. Author has developed a technology for the production of all oil and gas bearing zones encountered in a well through a single completion without allowing any inter layer cross flow. Author is extensively using TRIZ methodologies and highly benefitted with the application of TRIZ-a systematic approach for solving problems which was developed in Russia during 1946. In multiple tubing, simultaneous and segregated production is possible but the total system becomes complex. In commingle production, system is simple but interlayer cross flow is a problem. Moving from conventional to unconventional thinking, a hybrid completion system has been developed which retains the advantages of multiple tubing completions and commingle production and eliminating the disadvantages of both the systems.
In this paper author has tried to explain how TRIZ methodologies have helped him to develop an effective multiple zone well completion technology which will help other petroleum engineers to develop different innovative oilfield technologies using advanced innovative inventive tool like TRIZ.
The Central and Meridional Atlas of Tunisia, contains significant accumulations of oil in early Cretaceous aged reservoirs. The active cretaceous hydrocarbon system is a product of unique paleogeographic and tectonic events that led to cretaceous deposition of organic-rich source rocks.
The analysis of different sources rocks from the Central and Meridional Atlas of Tunisia indicates that the Albian Lower Fahdene Fm has a substantial oil-generation potential. The Cenomanian-Turonian Bahloul Fm exhibits fair to high organic matter content and petroleum potential and is immature to mature.The Jurassic source rock, located in the Southern part of this area, exhibits fair to good organic matter content and petroleum potential.
Molecular characterization indicates that most of the produced oils appear to be sourced from a predominantly shaly marine and mature source rock deposited in suboxic to oxic environment. Oil stains located in the northern part of the area seems to be sourced by a marly or argillaceous limestone. Oil-oil correlations and molecular characteristics of selected source rock samples and maturation models suggests that oils were generated from similar source rock and/or organic facies. The Lower Fahdene Fm is the best source candidate to generate these fluid samples. The integration of benzocarbazoles as geochemical molecules tracer has permitted a relative estimation of the lateral migration distance for the different accumulations of the area.
The hydrocarbon exploitation in Central Atlas of Tunisia started in 1968 and has been restricted to the Douleb, Semmama and Tamesmida oil fields. Recent drilling in this area has shown some hydrocarbon shows in the Lower Cretaceous series. In spite of the long history of exploration and production, few geochemical investigations were performed until now.
The main objective of this study is to highlight the petroleum system in the Central Atlas of Tunisia. Rock Eval, Light fraction, saturates and aromatics biomarkers techniques were performed in order to assess oil occurrence and geochemical characteristics of the source rocks. The integration of previous available geochemical data about source rocks and recovered or produced hydrocarbon samples allowed us to locate the paleo and recent kitchen areas and to retrace the hydrocarbon migration routes. This study was followed by basin modelling to underline more information on the infilling history of the area.
As engineers and scientists, we are very familiar with analysing technical risks, developing mitigation plans and implementing the plans that are safe and technically feasible. At the same time, dealing with subsurface projects has made us adept at analysing and understanding technical uncertainties. Furthermore, because of the large investments involved in upstream projects we are regularly exposed to commercial issues. However, the optimum situation is when the technical and commercial risks and uncertainties are evaluated in an integrated fashion.
Although many organisations combine technical and commercial evaluations, there are many examples that such integration is either superficial or is done in a series. Often the economic evaluation is performed at the end of the process, by which time it may be too late to influence the decisions or the changes may be too expensive to implement.
Techno-economic integration becomes absolutely essential when our industry faces "game-changing?? technologies, for example:
• Unconventional resource developments: Shale gas/oil
• Isolated gas monetisation: Gas to Liquid (GtL), Floating Liquefied Natural Gas (FLNG)
• Heavy oil developments: In-situ combustion, Steam Assisted Gravity Drainage (SAGD), Cold Heavy Oil Production with Sand(CHOPS)
Examples will be given to demonstrate the successes and failures of game changing technologies, where the failures are generally less advertised. It is important to discuss the ‘lessons learnt' from these important events in our recent history: How can we apply techno-economic evaluation in an integrated fashion (and at an earlier stage) to better evaluate risks and uncertainties associated with implementing game-changing technologies? How can we influence the outcome of these projects?
This discussion is particularly relevant to the North Africa region as governments, National Oil Companies (NOCs) and International Oil Companies (IOCs) try to harness unconventional resources and seek alternative ways to monetise their gas resources.
New concepts are introduced to define time lag and response amplitude. The points of extreme pressure values (maxima and minima) are used to define the time lag and pressure response amplitude. The points of maxima and minima are found by equating the pressure derivative to zero. This results in a more accurate solution of the governing equations. The developed method is based on well-defined and easily locatable points, making the method amenable to automatic analysis by computer procedures. It eliminates the need for manually plotting of parallel tangents to the pressure profiles which is subjective, less accurate and does not amend itself to automatic processing.
The solution is used to construct correlation charts for relative time lag and dimensionless pressure response amplitude vs. the dimensionless cycle time for different values of the pulse ratio. The correlation charts will be used to analyze results of pulse testing to obtain interwell reservoir properties, namely transmissibility kh/??? and storativity h???ct. Simulation examples are generated to validate the developed procedure. Results indicate the robustness of the developed method and its superiority over the conventional pulse test analysis method.
The developed correlations show that the relative time lad decreases linearly with the dimensionless cycle time on a log-log plot. Results also indicate that the relative time lag and dimensionless pressure response amplitude decrease with pulse ratio for odd pulses and increase for even pulses.
Pulse testing is an interference test (multiple wells) in which an active well and one or more observation (responding) wells are used in the test. The flow rate is controlled at the active well while the pressure response is recorded at the observation wells. These tests are used to verify communication between wells and to estimate inter-well properties. Reservoir anisotropy can also be detected by such tests when different observation wells are used (Chen, Hedayati, and Teufel 2000 and Alkoh and Chen 2008). By performing the tests at different times, the movements of different fluid banks can be monitored. This is important in secondary and enhanced oil recovery projects (Jha et. al. 2011)
In pulse testing, the rate at the active well is changed alternately between flow and shut-in conditions. This results in an oscillating component of the pressure response that can be easily identified for analysis. This is usually done by the tangent construction method to separate the oscillating component from the general trend of the pressure response. The time lags and pressure response amplitudes for different pulse cycles are determined from a plot of ???P vs. t on a normal scale (Johnson, Greenkorn and Woods, 1966). These parameters are related to the transmissibility T=kh/??? and the storativity S= h???ct. The analysis is based on the exponential integral solution of the diffusivity equation for homogeneous infinite reservoir and the use of the principle of superposition to handle the variable flow rate. Correlation charts to estimate reservoir properties from the time lag and pressure response amplitude were presented for equal (Brigham, 1970) and unequal pulse and shut-in periods (Kamal and Brigham, 1976). Ogbe and Brigham (1987) presented a method to correct for the skin and wellbore storage effects. They also found it necessary to correct the previously published Kamal-Brigham correlation curves. These correlation charts are constructed by solving a set of nonlinear equations numerically using an iterative procedure. These iterative methods may face convergence problems and the results will depend on the initial guess and convergence criteria which may make the results unreliable. Furthermore the manual plotting of parallel tangents and the necessity of using correlation charts make the results of this method questionable. Furthermore the conventional graphical method can't be used as a systematic computer-based analysis procedure that is most desirable. These factors made it desirable to find an alternative method that avoids the complexity and unreliability of the tangent construction method.
DCA (Decline curve analysis) is one of the most powerful tools used in defining well/reservoir worth. DCA aims at estimating reservoir production performance at any time (of production) post plateau period providing realistic and well documented production data. DCA helps in developing production-rate/reservoir-pressure distributions to determine well/reservoir productivity scheme. Forecasting well/reservoir production rate, estimating remaining reserves, monitoring GOR & WC behaviors, deciding on reservoir pressure support and determining economic limits are among the many befits of DCA as well.
In this study the AOR (Actual Oil Rate) method has been implemented utilizing the DCA, FASTRTA™ and Ecrin packages to calculate remaining and recoverable reserves in particular. The remaining reserves depend on the production data that are selected to represent the actual well/reservoir behavior. This technique allows eliminating misrepresenting production data due to human error, imposed production rates caused by internal company policy or external factors (politics, natural disasters, etc.) during production life of the field.
A case study has been used as a pilot for the proposed method. Analyses have been performed on both well and whole reservoir scale. The outcome yielded more realistic results using AOR and generated very useful development recommendations. The proposed AOR-DCA adopted technique can assist in accurate decisive parameters estimate of both mature and under-development oil reservoirs worldwide.
Fundamentally all oil and gas wells produce at a declining rate over time post plateau. The initial flow rate may be held constant on purpose by restricting the flow rate or the decline may begin immediately after plateau period. The ultimate recovery from the well can be calculated by projecting the decline rate forward in time to a set economic limit. The projected production can be summed to find the total production on decline, and this can be added to the production during the constant rate period (plateau) to obtain the ultimate recovery.
This can be done on well by well basis or for an entire reservoir. The result can be used as a control on the volumetric reserves calculated from log analysis results, seismic data and geological contouring of field boundaries. It is often used to estimate the recovery factor by comparing ultimate recovery with original oil/gas in place calculations.
DCA (Decline Curve Analysis) are plots of the theoretical solution to the governing flow equation for constant-rate production, or constant-pressure production, from a well in any kind of reservoir model. Generally, the operating conditions during production from a well are not constant. Hence, to analyze real production data, one needs to develop a robust methodology to account for these changes. This problem was solved by the use of the material balance time concept. By using this concept, one could have a single solution to the governing flow equation for both types (i.e., constant-rate and constant-pressure) of boundary conditions. It was shown that the same solution applies to cases where both rate and pressure are smoothly changing with time.
Decline curve analysis is used to estimate the ultimate recovery (reserve), predicting the future production rate and the production life of a reservoir or wells, and it greatly affected by the changes done on the reservoir, such as drilling of new wells, shutting-in some wells, and injection. Typical decline-curve analysis consists of plotting well production versus time on semi-log paper and attempting to fit these data points to straight line, which is then extrapolated into the future.