Unconsolidated Sandstone Formations Research Articles

A novel semi-analytical model for pore volume compressibility in oil-bearing sandstone formations

Rock compressibility is an essential parameter in many petroleum engineering applications, specifically in reservoir modeling. It is an independent variable that is not measured in conventional core analysis but can be estimated through correlations or using hydrostatic or triaxial tests (if available). In this research, a new semi-analytical model was reconstructed to estimate the isothermal rock compressibility in sandstone formations. The newly derived model was validated using raw data collected from the upper sandstone member/Zubair formation of several oil fields in southern Iraq.In this research, analytical equations and some empirical correlations were used to formulate a semi-analytical model to predict the isothermal rock compressibility. The derivation started with the equations of dynamic elastic properties of Young's Modulus and Poisson's ratio parameters to derive the static state of these two parameters. Specifically, Johan Fuller's correlation was utilized to find the static Young's Modulus, which was used with Poisson's ratio to compute the static bulk modulus. In the final step of the derivation, the compressibility equation was simplified to be a function of porosity only, which eliminates the effect of the static bulk modulus.The predictions of the derived model were compared with laboratory test measurements of pore volume compressibility, porosity, and elastic rock properties, and an acceptable matching was achieved. To support the accuracy and robustness of the new model, the results were compared with several available empirical correlations, and better matching was obtained by computing the Absolute Percent Error (AAPE), Mean Square Error (MSE), and Absolute Root MSE (ARMSE).Consequently, the new pore volume compressibility equation matches lab-measured data significantly. However, the lab-measured data showed poor compatibility with available equations in the literature. Therefore, this model should be accurate and robust for compressibility estimation in other oil-bearing consolidated and unconsolidated sandstone formations. Additionally, the newly derived equation is simple, uncomplicated, and easy to use.

Capillary pressure equilibrium theory mapping of 4D seismic inversion results to predict saturation in a gas-water system

Understanding the effect of fluid concentration in rocks is crucial to characterize a hydrocarbon reservoir. Monitoring of fluid concentration specifically becomes challenging during a sequestration/enhanced oil recovery program because the objective is to understand the amount of initial fluid replaced by liquid/gas injection and identify the probability of leakage with time. The prior assumption of uniform or patchy type of distribution of gas in a rock-physics theory leads to large uncertainty in the prediction of saturation. As a result, we have used the capillary pressure equilibrium theory (CPET) for creating a reservoir model that matches the physics of capillary-induced fluid invasion and avoids the uncertainty related to the type of distribution of gas in pores. We create a CPET model using the reservoir parameters of the clean and unconsolidated sandstone formation of the Sleipner field, North Sea, which is the world’s first industrial-scale CO2-injection project, assuming that there is no significant change in the rock frame throughout the field. The model is then used to analyze the fluid content from the time-lapse seismic inversion results of the Sleipner field. CO2 at higher quantities, according to our research, is analogous to a uniform distribution, whereas CO2 at lower concentrations is mostly in between patchy and uniform distribution or slightly patchy type. We predict maximum CO2 saturation from a quantitative interpretation of six time-lapse seismic data from 1999 to 2010 using the CPET as 75% of the pore space, and the footprint of the CO2 plume in the topmost layer is spreading from zero in 2001 to 7 × 105 m2 in 2010. Our model finds that injected CO2 from all layers below will migrate to the top layer approximately 50 years after the commencement of the injection.

Investigating the Impact of Sieve Analysis on the Choice of Gravel Pack Design for Wells in Unconsolidated Sandstone Formations in the Niger Delta

Sand production is major problem for the oil and gas industry and solutions to this problem is a continuous process as new challenges arise with time. Various sand control methods have been proposed for tackling the sand production challenge, and research and experience have shown that the use of mechanical sand control methods are more suitable, with gravel packing being the most effective. Gravel packs are proven to be an effective mechanical sand control technique, and a good gravel pack completion design is of great importance to exclude sand from the wellbore while enhancing well productivity. Implementation of sand control by gravel packing in the Niger Delta is usually found to require importation of commercial gravel for the purpose of sand control which is a challenge in terms of high purchasing and transportation costs with import taxes. A solution is presented in this study which involves sourcing for gravel locally and investigating its suitability for sand control by gravel packing. Locally sourced gravel was compared with commercial gravel using sieve analysis and results showed that the locally sourced gravel closely met the requirements of the commercial gravel depicted by slot widths that are close to that obtained by the commercial gravel. Based on the results of this study, favorable performance is expected when locally sourced gravel is used for sand control by gravel packing in unconsolidated formations in the Niger Delta. It is recommended to source for different gravel types from different locations and evaluate using sieve analysis and Laser Particle Size Distribution Analysis to determine suitable gravel types for these type of formations.

Mitigating Water Production from High Viscosity Oil Wells in Unconsolidated Sandstone Formations

Summary Large reserves of high-viscous oil in Kuwait call for improved oil recovery scenarios. In Kuwaiti unconsolidated sandstone formations, the sandstone intervals represent extensive reservoir intervals of sand separated by laterally extensive nonreservoir intervals that comprise finer-grained argillaceous sands, silts, and muds. The reservoir is shallow with high permeability (above 1,000 md) and under bottom aquifer pressure support. Due to strong viscosity contrast between oil and water, after breakthrough, the water cut rises quickly, resulting in strong loss of production efficiency. Mitigating water production is thus mandatory to improve production conditions. The candidate wells have two to three open intervals in different rock facies with comingle production. The total perforated length is between 38 and 48 ft. Production is through progressing cavity pumps (PCP) at a rate of around 300 B/D, and basic sediment and water is between 71 and 87%. The technology applied utilizes pregelled size-controlled product [small microgels (SMG Microgels)] having relative permeability modification (RPM) properties; that is, inducing a strong drop of relative permeability to water without affecting oil relative permeability. The size is chosen to selectively treat the high-permeability water producing zones while preserving the lower-permeability oil zones. The chemical can also withstand downhole harsh conditions such as salinity of around 170,000 ppm and presence of 2% H2S. The treatment consisted of bullhead injection of 300 bbl of pregelled chemical through-tubing. The first results seem very favorable, since for two wells, the water cut has dropped from 80 to 40% with almost same gross production rate. The incremental oil is more than 100 BOPD. The third well did not show marked change after water system operation (WSO) treatment. The wells are under continuous monitoring to assess long-term performance. Such result, if confirmed, may lead to high possibilities for the improvement of heavy oil reservoir production under aquifer support by mitigating water production with simple chemical bullhead injection.

Carbonate Rock Chemical Consolidation Methods: Advancement and Applications

Chemical consolidation of rocks is a common practice in the petroleum industry. Usually, this technique is applied to sustain production from unconsolidated or weak sandstone formations and to avoid collapse from aging wells. Recent research has shown the significance of rock hardness in sustaining long-term conductivity of hydraulic fractures in carbonate formations. There are some notable attempts to adapt the techniques used in the cultural heritage industry for strengthening carbonate formations. Moreover, a novel carbonate rock strengthening methodology was developed that involves the mineral transformation of calcite to harder minerals. This work describes the existing techniques for carbonate rock consolidation and provides extensive research on chemicals that are (or can be) used as carbonate rock strengthening agents. Furthermore, this review provides the reaction mechanisms associated with a range of proposed chemicals. Also, laboratory methods that can be used to assess post-treatment hardness and investigate the changes in rock mineralogy are summarized. Finally, the review discusses chemicals with the prospect of their application in petroleum field operations.

A new type of low density cement slurry suitable for sandstone formation

Unconsolidated sandstone reservoir is an important unconventional oil and gas resource with the characteristics of porosity, low permeability, strong heterogeneity and many interlayer. The main challenge of unconsolidated sandstone formation is sand production of oil wells, and the more serious situation is high-pressure oil and gas escaping, blowout accidents, environmental pollution and the safety of operators. In order to solve the sensitivity problem of loose sandstone, a low density admixture was developed: 10.5% artificial floating bead + 4.5% power plant floating bead + 35% micro silicon + 30% fly ash + 20% slag. The particle size distribution of single lightweight material is narrow, and the effect of reducing density is not significant. The developed low-density mixing material has wide and uniform particle size distribution, and can reduce the density of cement slurry to the maximum within the minimum dosage. The new low density admixture cement slurry with adjustable density in the range of 1.4 ∼ 1.7 g / cm3 has good rheological property, short thickening time, water loss less than 50 ml, 24 h compressive strength more than 12 MPa, which can meet the needs of site construction. The temperature and pressure test results show that the system has a wide range of temperature and pressure applications and stable performance. Compared with the similar low density cement slurry, it is about 40% lower than the market price and suitable for commercial application.

Mechanism and Effect of Nanoparticles on Controlling Fines Migration in Unconsolidated Sandstone Formations

Summary Pore throat blockage due to fines migration during drilling and completion is one of the leading causes of damage to unconsolidated sandstone reservoirs. Therefore, it is necessary to explore an effective control method for fines migration. Five types of nanoparticles in suspension with aqueous NaCl solutions of six different ionic strengths were chosen. Their ability to control the migration of quartz and kaolinite fines in quartz sand as the porous medium is discussed in this work. Results show that nanoparticles can effectively adsorb and fix fines, thus successfully suppressing their migration. Among these nanoparticles, Al2O3 showed the best performance, and nanoparticle suspensions with higher ionic strengths were preferable. A surface element integration method was used to establish a mathematical model for calculating the interaction energy between the formation fines and the rock pore surface with adsorbed nanoparticles. Through atomic force microscopy and zeta potential measurements, the effect of nanoparticle adsorption on the heterogeneity of the pore surface was analyzed in terms of roughness and electrical properties. The interaction energy between the formation fines and the heterogeneous pore surface was calculated; it revealed the microscopic mechanism of how nanoparticles control fines migration. The results indicated that the nanoparticles form an adsorption layer, which enhances the physical and chemical heterogeneities of the pore surface and provides favorable conditions for the adsorption and fixation of fines. As a result, the interaction energy curves of the fines and the pore surface shift downward, and their repulsive barriers decrease or even disappear, exhibiting higher attractive potential energy. These variations promote adsorption and fixation of fines at the pore surface, as confirmed by the experimental results reported in this work, thus successfully preventing formation damage.

A mechanistic study of smart water injection in the presence of nanoparticles for sand production control in unconsolidated sandstone reservoirs

In unconsolidated sandstone formations, fine sand particles movement as a result of contact between low salinity water (LSW) and rock surface minerals/interparticle cement disturbing the ionic equilibrium in the medium is recognized as the most common issue. Such unstable particles can obstruct some fluid paths and consequently, reduce the reservoir permeability and cause a type of formation damage. In this regard, adding nanoparticles (NPs) into the injected water may obviate shortcomings associated with sand production (SP). Charged NPs could easily adsorb onto the rock surface oppositely charged because of their ultra-small specific surface area and partially cover the rock surface. It can be as a protective layer for unstable minerals against the LSW as the destabilizer element. At these conditions, the solidity of the interparticle cement could stabilize the fine sand particles and impedes subsequent problems. In this study, a new approach has been introduced to optimize the composition of the SW using a statistical method. Moreover, the role of NPs in SP control during the SWI process has been surveyed here. The results obtained here reveal that adding silica NPs into the optimized injected water to unconsolidated sandstone samples not only enhances the oil recovery up to 10% but reduces about 81% of produced sand. NPs partial surface coating as a promising mechanism for stabilizing the fine sand particles has been proposed. The influence of SP on rock compressive strength has also been investigated and 46% improvement in rock strength was observed as a result of the presence of NPs in the injected fluid. Besides, for unconsolidated sandstones, an exponential trend of the weight of produced sand was observed and two empirical correlations have obtained to estimate the total mass of produced sand based on the type and the volume of the injected fluid. It is expected that this study could be helpful for a better understanding of acting mechanisms in the molecular scale behind the nano-assisted smart water injection (NSWI) for SP control in unconsolidated sandstone formations.

Chemical Sand Consolidation: From Polymers to Nanoparticles.

The chemical sand consolidation methods involve pumping of chemical materials, like furan resin and silicate non-polymer materials into unconsolidated sandstone formations, in order to minimize sand production with the fluids produced from the hydrocarbon reservoirs. The injected chemical material, predominantly polymer, bonds sand grains together, lead to higher compressive strength of the rock. Hence, less amounts of sand particles are entrained in the produced fluids. However, the effect of this bonding may impose a negative impact on the formation productivity due to the reduction in rock permeability. Therefore, it is always essential to select a chemical material that can provide the highest possible compressive strength with minimum permeability reduction. This review article discusses the chemical materials used for sand consolidation and presents an in-depth evaluation between these materials to serve as a screening tool that can assist in the selection of chemical sand consolidation material, which in turn, helps optimize the sand control performance. The review paper also highlights the progressive improvement in chemical sand consolidation methods, from using different types of polymers to nanoparticles utilization, as well as track the impact of the improvement in sand consolidation efficiency and production performance. Based on this review, the nanoparticle-related martials are highly recommended to be applied as sand consolidation agents, due to their ability to generate acceptable rock strength with insignificant reduction in rock permeability.

Porothermoelastic response of an oil sand formation subjected to injection and micro-fracturing in horizontal wells

Stimulation of unconsolidated formations via horizontal wells has seen its vast implementation in the recent development of heavy oil reservoir to save the time and cost of preheating the reservoir before the steam-assisted gravity drainage (SAGD) process. A mathematical approach was proposed in this research that fully couples the hydraulic, mechanical and thermal responses of unconsolidated sandstone formations and also applies failure criteria for describing either shear dilation or tensile parting mechanism that generates microcracks. The approach was implemented to predict the porothermoelastic response of a pair of SAGD wells subject to injection and subsequent micro-fracturing using hot water. It was found that the predicted bottom hole pressures (BHPs) match closely with the field observed data. An elliptical dilation zone developed around the dual wells with relatively high pore pressure, porosity, permeability and temperature, implying good interwell hydraulic communication between both wells. The activation of microcracks dramatically accelerated the dissipation of pore pressure across the entire formation depth and also facilitated heat convection in between the dual wells, though to a lesser extent. In summary, the approach provides a convenient means to assist field engineers in the optimization of injection efficiency and evaluation of interference among multiple horizontal wells.

Development of water-based drilling fluid used in unconsolidated sandstone reservoir

ABSTRACT According to the fact that there is some little research on drilling fluid used in unconsolidated sandstone reservoir while conventional drilling fluid can not meet the requirements, we developed a new kind of water-based drilling fluid system. In this paper, bentonite, filtrate reducer, inhibitor, and other additives were optimized according to the characteristics of unconsolidated sandstone formation and several properties like rheology, filter loss, inhibition, and so on. A new drilling fluid system was developed and it was finally determined to be 5% Na2CO3 + 4% bentonite +0.2%PAC+ 0.7%FLA1 + 2%IHT1 + 3%GSJ +0.8% WHA1. The density, apparent viscosity, plastic viscosity, and yield point of this system were 1.18 g/cm3, 38.2 mPa·s, 24 mPa·s, and 17.2 Pa, respectively. Its filter loss was 6.2 ml, thickness of filter cake was 0.5 mm, roll recovery of rock samples was 88%, and the expansion amount was 0.18 mm. In immersion experiment, there was no obvious cracks on core samples. The result showed that this drilling fluid system can effectively clean the unconsolidated sandstone borehole and its filter loss performance, rejection capability, and antipollution properties were pretty good.

Numerical Investigation of Sand-Screen Performance in the Presence of Adhesive Effects for Enhanced Sand Control

Summary In many industrial processes, an effective particle–filtration system is essential for removing unwanted solids. The oil and gas industry has explored various technologies to control and manage excessive sand production, such as by installing sand screens or injecting consolidation chemicals in sand–prone wells as part of sand–management practices. However, for an unconsolidated sandstone formation, the selection and design of effective sand control remains a challenge. In recent years, the use of a computational technique known as the discrete–element method (DEM) has been explored to gain insight into the various parameters affecting sand–screen–retention behavior and the optimization of various types of sand screens (Mondal et al. 2011, 2012, 2016; Feng et al. 2012; Wu et al. 2016). In this paper, we investigate the effectiveness of particle filtration using a fully coupled computational–fluid–dynamics (CFD)/DEM approach featuring polydispersed, adhesive solid particles. We found that an increase in particle adhesion reduces the amount of solid in the liquid filtrate that passes through the opening of a wire–wrapped screen, and that a solid pack of particle agglomerates is formed over the screen with time. We also determined that increasing particle adhesion gives rise to a decrease in packing density and a diminished pressure drop across the solid pack covering the screen. This finding is further supported by a Voronoi tessellation analysis, which reveals an increase in porosity of the solid pack with elevated particle adhesion. The results of this study demonstrate that increasing the level of particle agglomeration, such as by using an adhesion–promoting chemical additive, has beneficial effects on particle filtration. An important application of these findings is the design and optimization of sand–control processes for a hydrocarbon well with excessive sand production, which is a major challenge in the oil and gas industry.

A data-driven model for predicting the effect of temperature on oil-water relative permeability

Several empirical models have been proposed by scholars to capture the temperature’s impact on relative permeability for a specific rock/fluid system, often using very limited dataset of measured relative permeability values, which makes these models inapplicable to a wider range of rock-fluid characteristics. The current study presents a new data-driven model to predict the two-phase oil/water relative permeability over a wide range of temperature in unconsolidated sand and sandstone formations. We found that the carbonate rock systems have different characteristics and the reported high temperature relative permeability data for them is limited, which prevented us from including them alongside the sand systems. For developing the model, the Least Square Support Vector Machine (LSSVM) in the form of a supervised learning approach was implemented, in which the coupled simulated annealing optimization technique was employed for calculation of LSSVM hyper-parameters. To gather a comprehensive dataset for constructing the model, 626 experimental oil relative permeability and 547 experimental water relative permeability data points were obtained from the open literature. To identify the doubtful data points (the outliers) the method of Leverage Value Statistics was applied. The temperature (ranging from 21 to 200 °C), water saturation, oil viscosity (ranging from 0.42 to 1190 cP), water viscosity (ranging from 0.136 to 1.1 cP), and the absolute permeability (ranging from 152 to 95,000 mD) were used as the independent variables in the model. The statistical analysis of the obtained LSSVM for prediction of relative permeability demonstrated that the coefficient of determination, root mean square error, and average absolute error were 0.9987, 0.0111, and 5.36% for oil relative permeability and 0.9991, 0.0056, and 8.40% for water relative permeability. The comparison of statistical parameters of this model with other reported relative permeability models showed that this model is more reliable for estimating the oil and water relative permeability including its dependence on temperature and therefore it can be used for reservoir simulation studies, when experimentally measured data are not available.

Surface modified proppants used for porppant flowback control in hydraulic fracturing

In order to solve the problem of proppant flowback in postfrac fracturing fluid flowback treatments and hydrocarbon productions, new heterocyclic polymer modified proppants were introduced. The most important characteristic of the modified proppants is self-aggregation in the water environment. Due to this special character, an evaluation method based on ultrasonic oscillation effect is developed to measure the aggregating strength of the proppants congeries, with which the optimal formula and the recommended dosage are determined. By virtue of the reaggregating property of the modified proppants, which is different from the one-time bonding effect of resin coated proppants, the fracture conductivity and the proppant flowback control ability are improved greatly. Experimental results show that with the dosage of 1.0% of the PFVP, the strength of the reaggregating column decreases by 54.6% after ten times of collapse and reaggregation, which is even big enough for proppant flowback control. The larger the dosage of PFVP is, the higher the strength of the reaggregating proppant column regains. Compared with untreated proppants and resin coated proppants, the maximum sand free flow rate of the modified proppants increases by 80.6% and 39.8%. The higher the closure stress is, the more obvious the proppants flowback control ability is. In addition, the formation fines adsorption property of the PFVP modified proppants endows the self-cleaning property of the flow channels in the fracture. The results provide a new alternative for proppant flowback control, especially in unconsolidated sandstone formation with high closure stress.

Application and Analysis on Sand Control Technique for Unconsolidated Sandstone Formation

For unconsolidated sandstone formation, sand control problem is very important. Packing sand control materials into unconsolidated sandstone is a good idea to improving the flow conditions and stabilizing sand of down hole formation. Some application and analysis on sand control technique for unconsolidated sandstone formation are introduced in this paper. A simplified model for sand control material’s application has established. Some sensitivity of prediction and production-increasing effect are analyzed. Good conclusions are found. This technique is fit for light oil reservoir. The ratio of water reducing will decrease with the thickness of sand control materials decreasing and the oil viscosity increasing. Key words: Sand control materials; Application effect; Simplified model

Rheology and polymer flooding characteristics of partially hydrolyzed polyacrylamide for enhanced heavy oil recovery

AbstractPolymer flooding characteristics of partially hydrolyzed polyacrylamide (HPAM) solution with the addition of NaOH were examined in homogeneous glass‐bead packs. The heavy oil recovery in unconsolidated sandstone formations by applying the alkali‐polymer flooding was observed. Experimental results showed that HPAM solution was sensitive to temperature, salinity, and alkali, finding that alkali‐polymer solutions are more effective in improving viscosity than conventional polymer solutions. The solution of 0.5 wt % NaOH mixed with 1500 ppm HPAM (12 mol % hydrolysis degree) was found to be the optimal choice, which gives rise to the highest viscosity on the rheological characterization. Flood tests using the alkali‐polymer solution showed an increase in oil recovery by 30% over water‐flooding when the water‐cut reached 95%, indicating that alkali‐polymer could be more effective in improving sweep efficiency than polymer flood. © 2012 Wiley Periodicals, Inc. J. Appl. Polym. Sci., 2013

Thermal and mechanical evaluation of the stability of recycled poly(ethylene terephthalate) applied as sand control agent in petroleum wells

In petroleum wells, the granular sand control agents commonly employed are basically inorganic compounds, which are used in operations to prevent the production of sand, from unconsolidated sandstone formations, that contaminates the produced hydrocarbons. In this work the viability of applying recycled poly(ethylene terephthalate) (PETrec) as sand control agent, in an environment that simulated the conditions of the wells, was evaluated. Virgin PET (PETvir) was tested as a standard for comparison means. Pellets of each polymer (PETrec and PETvir) were confined into metallic cells filled with sea water or petroleum, under conditions observed in some sandstone formations that are normally subjected to sand control, in Campos Basin (Rio de Janeiro, Brazil). The cells systems were submitted to a controlled temperature of 70 °C and pressure of 24.1 MPa, and rolled during the experiment period. The total exposure time was approximately six months (172 days), with scheduled sampling periods. Thermal, mechanical and granulometric properties of the pellets before and after the exposition were evaluated. The samples were characterized by differential scanning calorimetry (DSC) and thermal gravimetric analysis (TG). Mechanical experiments were performed, in order to determine the grain pack permeability, by the end of the exposition period, according to API RP 58 and API RP 61 standard methods. Particle size of the grains, before and after the exposure process, was compared. Test results showed that PETrec and PETvir samples did not present significant physical changes or evidences of degradation, nor in water neither in petrol, suggesting that the use of recycled PET as sand control agent seemed to be viable within the experiment conditions.

Achieving Solids-Free Gas-Production Target Rate From Highly-Unconsolidated-Sandstone Formation Intervals

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 141878, ’Achieving Target Solids-Free Gas Rate From Highly- Unconsolidated-Sandstone Formation Intervals,’ by Nahr Abulhamayel, J. Ricardo Solares, SPE, Walter Nunez, Ataur Malik, SPE, Mustafa Basri, SPE, and Andrew McWilliams, Saudi Aramco, and Oumer Tahir, SPE, and Mohammad Abduldayem, SPE, Weatherford, prepared for the 2011 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 20-23 March. The paper has not been peer reviewed. One of the most challenging aspects of producing wells drilled in the unconsolidated pre-Khuff gas reservoirs in Saudi Arabia is to achieve solids-free production while trying to achieve high gas rates. Challenging reservoir conditions include high temperature and pressure, high stress, heterogeneity, and the absence of stress barriers that together make placing fracture treatments very difficult. Stand-alone screens were installed in openhole well completions in the sandstone reservoir and achieved excellent results by eliminating the need for a fracturing treatment. Introduction Achieving solids-free production from unconsolidated-sandstone reservoirs is an ongoing challenge. The importance of effective sand control in these wells is the need to maintain the integrity of bottomhole and surface processing equipment and facilities, and to ensure that production targets are met consistently. Fig. 1 shows examples of the potential damage that sand production can cause. Several approaches including indirect hydraulic-fracturing stimulation, high-angle and increased-contact wells, and, more recently, sand-screen completions have been used to develop these gas reserves. Among these approaches, the sand-screen completions, in both vertical and high-angle wells, was field tested in two wells, and then it was implemented in more wells after the success of the pilot. Formation Geology The sandstone formation in which the two well pilot tests were conducted is a siliciclastic formation in the pre-Khuff stratigraphic section in Saudi Arabia. Gas resources are in sandstones of variable quality within a sequence of sandstones, siltstones, mudstones, and shales. Because the formation was deposited in a shallow marine tidally influenced shoreline setting, it is heterogeneous in character. Heterogeneity imposes both vertical- and lateral-distribution variability of reservoir-quality properties over a wide range of scale and geometry. Reservoir quality in this sandstone formation is a function of several factors, particularly grain size and sorting and clay type and content, which are controlled largely by the primary sedimentological process. Sandstone cementation and diagenesis-controlled cementation also play a role. These reservoir-quality-influencing factors are, in turn, subject to sedimentological and diagenetic processes, controlled largely by the depositional setting. Porosity and permeability of the gas-bearing intervals vary over a wide range. The well-plan metric for the initial gas-production rate from the formation is from 15 to 20 MMscf/D. Although this rate is achievable, given the permeability and pressure characteristics of the reservoir, the formation’s unconsolidated nature increases the risk of exposing equipment to damaging sand production.

Horizontal-Wellbore Stability and Sand Production in Weakly Consolidated Sandstones

SummaryLong-term stability of horizontal wellbore completions with uncemented liners in weakly consolidated to unconsolidated sandstone formations (e.g., the Gulf of Mexico and Nigeria) remains an area of concern. In this paper we present the results of dedicated polyaxial cell laboratory experiments that address this issue. In addition, the influence of rock failure in the near-wellbore region on well productivity was studied.Large blocks of a weak artificial sandstone were prepared. A hole was drilled in these blocks, and production conditions at various values of in-situ stress, drawdown and water cut, both in the absence and presence of a liner, were simulated. During testing, the hole was kept at a horizontal position in order to realistically simulate the influence of gravity forces on the movement of sand debris. The process of hole failure and re-stabilization was continuously monitored by an endoscope coupled to a video camera.The experimental results show that in the presence of a slotted liner, and in the absence of a water cut, rock failure leads to gradual annulus fillup with loose sand, eventually resulting in a stable configuration in which only a small fraction of the far-field stresses is transferred to the liner. These results are further supported by elasto-plastic calculations. Rock failure around the liner is shown to have only a minor effect on productivity. This result implies that rock failure around uncemented liner completions will generally not be noticed at the wellhead.The introduction of a small (<5%) water cut resulted in massive sand production and subsequent liner collapse. This can be explained by the fact that a water cut destroys capillary cohesion, thereby destabilizing sand arches over the slots.

Factors Affecting Sand Production from Unconsolidated Sandstone Saudi Oil and Gas Reservoir

In this work a physical model has been constructed to simulate sand production from oil and gas reservoirs. The model can accommodate unconsolidated as well as consolidated sandstone cores. The experiments were designed to investigate the effect of confining pressure, flow rate, and the displacing fluid viscosity on sand production mechanism in unconsolidated sandstone formations. Saline water (3.5% NaCl by weight), light (35° API) and heavy (27° API) crude oils were used as displacing fluids in the tests. The main goal of this study was to examine if controlling of the production rate alone can solve the problem of sand production in a Saudi oil reservoir. The oil reservoir is situated in an unconsolidated sandstone formation. A produced sand sample was obtained from this reservoir. Tests were conducted on sand packs having a similar granulomere distribution to that of the reservoir.The experimental results showed that, the magnitude of sand production from the tested porous medium is strongly affected by both flow rate and confining pressure. Sand production decreases with increasing confining pressure and/or decreasing flow rate. Only very fine particles of the porous medium are produced at high confining pressures. When water, or low viscosity crude oil are saturating the porous medium, sand production problem can be managed by controlling the flow rate. In case of saturating the porous medium by heavy crude oil, sand production mechanism becomes different and therefore, controlling only the flow rate cannot stop sand production. Hence, alternative sand control measures must be applied to control sand production in heavy crude oil reservoirs such as down hole emulsification, gravel packing, screen liners, or down hole consolidation.