Unconsolidated Reservoirs Research Articles

A resolved CFD-DEM investigation into sand production under water flooding in unconsolidated reservoir

Excessive sand production in the wellbore can impede oil production from unconsolidated reservoirs. The study reports an investigation of numerical simulation of sand production in oil-water two-phase flow. The interaction between fluid and particles is achieved by coupling the discrete element method (DEM) with resolved computational fluid dynamics (CFD). By harnessing the advantages of the method, the numerical model can capture the movement of particles and the changes in fluid field at a scale smaller than fine particles. The model reveals the water flooding process in the granular matrix and effectively visualizes the microscopic mechanisms of particle migration. The results indicate that the model with water flooding exhibits higher produced mass compared to the model without water flooding. Parametric analysis shows that there is a critical fines content, which leads to the maximum sand production. With the increase of viscosity and the decrease of interfacial tension, the sand production increases.

A resolved CFD-DEM investigation of near-wellbore fine sand migration and production during methane hydrate extraction

Methane hydrate extraction from unconsolidated reservoirs can face challenges due to excessive sand production in the wellbore. Sand production has long been a concern in petroleum engineering and has been extensively studied by researchers. This study investigates sand production in gas-water two-phase flow through numerical simulations. The simulations incorporate the discrete element method (DEM) and resolved computational fluid dynamics (CFD) to model the solid-fluid interaction，which allows for simulating the particle movements and capturing the variations in hydraulic properties of the granular sample at a particle scale. Additionally, a volume of fluid (VOF) method is employed to simulate the two-phase flow. The numerical model provides insights into the gas movement process within the granular matrix and visually depicts the microscopic mechanisms of particle migration during methane hydrate extraction. The results of the study demonstrate that the model incorporating gas injection, which involves injecting a predetermined volume of gas at the inlet to the fluid model, yields a higher mass of produced sand compared to the model without gas injection. Furthermore, as the volume of gas injection increases, the produced mass initially rises and then declines. In addition, parameter analysis shows that the pattern of sand production differs between the model with a higher fines content and the model with a lower fines content. With the increase of hydraulic gradient, the produced mass increase.

An Improved Continuum Approach for Unconsolidated Formations on the Field Scale

Summary With the development of unconventional resources, such as oil sands and methane hydrate reservoirs, the importance of the mechanical performance model for underground unconsolidated rocks has increased significantly. The commonly used numerical approach for unconsolidated rocks is the discrete-element method (DEM). However, the extensive calculations required by the DEM make it inadequate for simulating unconsolidated rock behavior on a field scale. An alternative is the continuum approach, used to simulate the behavior of unconsolidated rocks on the field scale. In previous continuum approaches, unconsolidated rocks have been modeled as a visco-plastic fluid (i.e., Bingham fluid). The continuum approach based on visco-plastic fluid uses pressure (scalar) to describe the stress state of the particles. However, this approach does not account for the difference between the maximum and minimum principal stresses of the in-situ stress field when simulating the mechanical performance of unconsolidated rocks. Here, we developed an improved continuum approach for unconsolidated rocks and used the finite-element method as a numerical approach. Our improved model can consider the difference between the maximum and minimum principal stresses of the in-situ stress field and the pore pressure of the unconsolidated formation. We validated our numerical model with the angle of repose test, a benchmark problem for unconsolidated rocks. The validation results confirm the accuracy of our unconsolidated model. For the coupled model between the unconsolidated model and the flow model, we used an analytical solution to verify its reliability. Unconsolidated rock performances in an unconsolidated reservoir with fluid injection have been investigated based on our coupled model. The simulation results show that injection can activate the movement of unconsolidated rock particles, leading to changes in the distribution of effective stress and permeability. Our model has the potential to address large-scale unconsolidated rock issues and contribute to energy extraction.

A comprehensive study of fines migration in internally unstable natural gas hydrate reservoirs

Evaluating unconsolidated reservoirs' internal stability concerning fine migration is essential for the commercial development of natural gas hydrate resources. In this pursuit, we use our newly developed visualized sand production cell and validated CFD-DEM model to study the fines migration dynamics in unconsolidated reservoirs. Our approach leveraged the novel Analysis Software for the Internal Stability of Granular Soils (ASISGS), equipped with three distinct criteria. Experimental observations revealed reservoirs with smaller fine particles experience intensified sand production, characterized by extended production durations and a heightened presence of fine particles in the produced sand. The fine particles move faster than the coarse ones. The ‘coarse matrix with floating fines’ is a premise for fines migration. The flow channel severely clogged by fine particles may reopen, leading to erosive bursts. Kezdi law and the Kenney and Lau criterion in ASISGS software successfully assessed reservoirs' internal stability, consistent with our experimental results. However, the Sherard criterion sometimes overestimated the reservoir's internal stability. Rather than a binary distinction, our research posits a continuum between internally stable and unstable reservoirs. From a CFD-DEM perspective, we discerned two predominant failure modes leading to sand production: erosion of fines and destabilization of the primary sand arch subsequently triggering a sand skeleton reorganization. The smaller the fine particle size, the slower the coordination number increase, the lower the coordination number the platform reach, and the more significant the fine particle migration. With the hydrodynamic drag force exerted by the fluid, fine particles move faster and farther than coarse particles. The formation process of the sand arch includes initial, migration, and equilibrium stages. Overall, this study offers valuable insights into fines migration and its impact on sand production, providing a foundation for effective sand management in natural gas hydrate reservoirs.

Experimental investigation of viscous oil–water–sand flow in horizontal pipes: Flow patterns and pressure gradient

Fluid production from unconsolidated reservoirs often leads in sand production, which poses a number of issues. Sand deposition in flowlines can result in significant pressure dips, pipe and facility damage, and obstructions that decrease productivity. More research is needed to understand the movement and deposition of sand in oil–water–sand (O–W–S) fluxes. This article focuses on O–W–S flows in a 6-meter-long horizontal pipe with an inner diameter of 0.0381 m. The study looks at the flow behavior of high viscosity oil–water (O–W), water–sand (W–S), and oil–water–sand (O–W–S) flows. Experiments were carried out at 250 psig pressure in a laboratory flow test facility using various heavy synthetic oils (viscosities ranging from 3500 cP to 7500 cP at 25°C) and tap water. The sand concentration varied from 1% to 10%, with an average sand particle diameter of 145 μm and material density of 2630 kg/m3. Water cuts ranged from 0.0 to 1.0. The experimental results revealed a minor change in pressure gradient between (O–W) and (O–W–S) flows. However, increasing the sand concentration in (O–W–S) flow resulted in higher pressure losses. The reduction factor of pressure gradient indicated that the highest decrease in pressure drop occurred at higher superficial oil velocities. Furthermore, a direct relationship was observed between the reduction factor and the decrease in water cut. The results also showed that the minimum required transportation velocity for sand slurry decreased with increasing superficial oil velocity, while the minimum transportation condition increased with higher sand concentration. The comparison between the expected pressure gradient from Bannwart and McKibben et al. and the actual experimental data demonstrated significant accuracy for the oil viscosities and superficial oil velocities used in the study.

Experimental study of fines migration in gap-graded soils with gas production: Implications to hydrate production from unconsolidated reservoirs

Methane hydrate production from unconsolidated reservoirs could be hampered by excessive sanding, which has been particularly noticed during gas production from hydrate-bearing sediments in the deep ocean. The sanding process involves the interaction of liquid, gas, particles, and phase change. Here we present an experimental study of production-induced fines migration under K0 pressure in a gap-graded sediment by using a transparent horizontal permeameter that allows the sand production process to be recorded. Effervescent powders, which release carbon dioxide when exposed to water, are used to simulate hydrate, producing gas in unconsolidated sediments to reproduce the phase change process. Our results show that permeability decreases due to pores being filled by gas in the initial stage of pressure variation, which further leads to the sudden collapse of the specimen, manifested by a burst period on the erosion curve. For the gap-graded soil with low fines content, gas fills the pores and accelerates the flow to wash away more fine grains. As the fines content increases, the effect of gas on the finial erosion weight decreases. The erosion localization is more severe, and the formation time of the flow channel is shorter in the soil with gas generation and high fines content. Once the flow channel is formed, erosion in the remaining areas is reduced as water flows converge into the flow channel. Sensitivity analysis shows that the final erosion weight increases with increasing grain size ratio, fine grain content, and effervescent powder content. As the size of effervescent powder increases, the final erosion weight also increases.

Coarse-graining of CFD-DEM for simulation of sand production in the modified cohesive contact model

Sand production is an important issue for many hydrocarbon recovery applications in unconsolidated reservoirs. The model using the computational fluid dynamics coupled with discrete element method (CFD-DEM) can capture micro-scale features of sand transport problems. In this study, coarse-graining methods of a three-dimensional CFD-DEM model are developed to investigate the sand production phenomenon. The modified cohesive contact model is utilized for the simulations with a sample based on particle size distribution obtained from the unconsolidated sandstone reservoir in Kazakhstan. The derivation of scaling from the fine model to the coarse model is presented rigorously. The original (fine scale) model is validated to the laboratory results including the cumulative sand production rate. The results of the original model is compared to the same statistic weight (SSW) and the same size parcel (SSP) coarse-gained models. The original and coarse-grained models show good agreement in the fluid streamlines, fluid and particle velocities. In terms of sand production rate, the SSW model results are more accurate than the SSP model. Moreover, the particle size distribution of the produced particles of the SSW model is consistent with the results of the original particle model. The SSP model performs better in terms of speedup by accelerating the original model up to 9.4 times in parallel computing.

Standardization of Particle Size for Floating Particle Wettability Measurement for Carbonate Rocks.

Misrepresentation of the wettability of a reservoir can lead to potentially low ultimate hydrocarbon recovery resulting in substantial economic losses. At the same time, it is impossible to determine the wettability of a reservoir across its length and breadth on a continuous basis using standard procedures. This work presents the development and standardization of a quick, easy, and low-cost wettability measurement method using the adherence tendency of rock particles in the oil or aqueous phase. The most important aspect of this study was establishing the optimum particle size for sustained floatation and balancing the buoyancy and gravity effect. The results show that the particles sink with a larger than optimum particle size because of the gravity effect. Similarly, the particles would float if they are smaller than optimum due to buoyancy and viscosity advantages. A new scale is designed, and the midpoint analysis shows that a 63-90 μm particle size is the ideal size range for the carbonate reservoir's wettability measurements, as the midpoint of the size distribution coincides with the standard Amott-Harvey (A-H) index. However, this size range is found to be wider for oil-wet particles. The floating particle method has several advantages over the established methods once standardized against a reliable process. Not only is the process fast but it can be performed with basic laboratory tools and does not require a high skill set. Most importantly, reliable wettability information can be obtained from drill cuttings and core fragments, enabling the determination of reservoir wettability on a continuum basis and not as a point basis, thus providing a more reliable average value, particularly for heterogeneous and unconsolidated reservoirs.

Quantitative Characterization of Shallow Marine Sediments in Tight Gas Fields of Middle Indus Basin: A Rational Approach of Multiple Rock Physics Diagnostic Models

For the successful discovery and development of tight sand gas reserves, it is necessary to locate sand with certain features. These features must largely include a significant accumulation of hydrocarbons, rock physics models, and mechanical properties. However, the effective representation of such reservoir properties using applicable parameters is challenging due to the complicated heterogeneous structural characteristics of hydrocarbon sand. Rock physics modeling of sandstone reservoirs from the Lower Goru Basin gas fields represents the link between reservoir parameters and seismic properties. Rock physics diagnostic models have been utilized to describe the reservoir sands of two wells inside this Middle Indus Basin, including contact cement, constant cement, and friable sand. The results showed that sorting the grain and coating cement on the grain’s surface both affected the cementation process. According to the models, the cementation levels in the reservoir sands of the two wells ranged from 2% to more than 6%. The rock physics models established in the study would improve the understanding of characteristics for the relatively high Vp/Vs unconsolidated reservoir sands under study. Integrating rock physics models would improve the prediction of reservoir properties from the elastic properties estimated from seismic data. The velocity–porosity and elastic moduli-porosity patterns for the reservoir zones of the two wells are distinct. To generate a rock physics template (RPT) for the Lower Goru sand from the Early Cretaceous period, an approach based on fluid replacement modeling has been chosen. The ratio of P-wave velocity to S-wave velocity (Vp/Vs) and the P-impedance template can detect cap shale, brine sand, and gas-saturated sand with varying water saturation and porosity from wells in the Rehmat and Miano gas fields, both of which have the same shallow marine depositional characteristics. Conventional neutron-density cross-plot analysis matches up quite well with this RPT’s expected detection of water and gas sands.

Robust and Fit-for-Purpose Sand Control Technology to Produce Marginal Reserves in EKP

East Kalimantan Petroleum (EKP) is an oil and gas exploration and production company which operates in East Kalimantan, Indonesia. Development of mature fields was aiming shallow unconsolidated sand-stone reservoirs which have high sand risk character. The proportion of shallow wells development compared to the main zone wells is tend to increase recently which has natural consequences of the increasing trend of sand-produced volume along with the hydrocarbon production. The sand grains abrasive physical property may cause consequences of a detrimental to the short-long-term productivity of oil and/or gas well. It can damage the hydrocarbon-contained surface facilities, and even causes a serious to catastrophic safety accident. The loss of containment leads might be followed by deadly disaster, such as fire and environment pollutions. The company currently produces these reservoirs type by applying the robust diesel-based chemical sand-consolidation (DB-SCON) technology for high stakes reservoirs and combined with the mechanical sand-screens application for the low stakes reservoirs. Along the field’s production period, the trend of a shallow unconsolidated reservoir’s average reserves is decreasing which lead to the declining trend of sand-control project economics. The company forms a project team under well intervention department to perform the research with the mission to find the new robust and fit-for-purpose sand-control technology application to produce the marginal reserves. The root causes analysis using current reality tree (CRT) reveals the three main factors of this economics declines trend: high chemical sand-consolidation investment cost, low-productivity and low-reliability of current mechanical sand-screen. The Analytical hierarchy process (AHP) defines the most robust and fit-for-purpose sand-control technology among the proposed alternatives: water-based chemical sand-consolidation (WB-SCON), high erosion resistance sand-screen (HERSS) and sand management (SM) technologies. As the result, the HERSS technology is chosen as the best solution among the alternatives. The field trials result compares HERSS performance to current robust DB-SCON. HERSS significantly reduces the investment cost by 68.0%, maintaining the reliability or success at 88.2% (DB-SCON recorded as 88.5%), maintaining the productivity at 2.5 MMscfd (gas production), accelerates the production two weeks earlier, and reduce the economic cut-off reserve limit from 0.1 down to 0.02 BCF. HERSS (made by zircon metal) technology is capable to significantly improve the performance of the mechanical sand-screen (Ceramic screen as current base-case). It increases the reliability from 64.7% to 88.5%, decrease the investment cost by 30.7%. The HERSS industrialization is planned in 2023 to replace current sand-control technology that potentially will generate significant economic improvement from the investment cost reduction with a total of $27.4 million.

Numerical simulation on the effects of fracture parameters on oil and water production in unconsolidated reservoirs

Numerical simulation on the effects of fracture parameters on oil and water production in unconsolidated reservoirs

A case study in the use of optimized technology for chemical sand consolidation in the bottomhole zone

Extraction of oil and gas from unconsolidated reservoirs induces complications, like bottomhole zone failure or sand production. The article gives an overview of the bottomhole zone consolidation with the Polyskrep agent. It gives laboratory and field test results of the optimized method of treating wells complicated with sand production.

Study of the Appropriate Well Types and Parameters for the Safe and Efficient Production of Marine Gas Hydrates in Unconsolidated Reservoirs

The majority of marine hydrates are buried in unconsolidated or poorly consolidated marine sediments with limited cementation and strength. As a result, hydrate decomposition during production may cause significant subsidence of the formation, necessitating a halt in production. The numerical model of unconsolidated hydrate formation, based on geomechanics, was established in order to elucidate the depressurization production process. The sensitive factors of unconsolidated hydrate production were determined by analyzing the influence of formation parameters and production parameters on gas production. Then, a safety formation subsidence was proposed in this paper, and the appropriate well type and parameters for the safe and efficient production of hydrates in unconsolidated formations of various saturations were determined. The sensitivity of gas production to the formation parameters was in the order of formation porosity, hydrate saturation, and buried depth, while the effects of the production parameters were BHP (bottom hole pressure), horizontal length, and heat injection, in descending order. For hydrate reservoirs in the South China Sea, when hydrate saturation is 20%, a horizontal well is necessary and the appropriate horizontal length should be less than 80 m. However, when hydrate saturation is more than 30%, a vertical well should be selected, and the appropriate bottom hole pressure should be no less than 3800 kPa and 4800 kPa for 30% and 40% saturation, respectively. Based on the simulation results, hydrate saturation was the key factor by which to select an appropriate production technique in advance and adjust the production parameters. The study has elucidated the depressurization production of marine unconsolidated hydrate formations at depth, which has numerous implications for field production.

Hydro-mechanical coupled analysis of near-wellbore fines migration from unconsolidated reservoirs

Hydro-mechanical coupled analysis of near-wellbore fines migration from unconsolidated reservoirs

High-pressure heavy oil saturation treatment method of outcrop core based on loose sandstone heavy oil reservoirs

The unconsolidated sandstone heavy oil reservoir is dominated by heterogeneous elastic-plastic reservoir with complex structure. The core demand is large in the study of reservoir lithology and physical properties. Although the high-cost freezing and encapsulation processes are used in the process of coring site and indoor processing, they are still easy to damage in the process of extracting cores. Moreover, the physical parameters of ordinary artificial cores are too different from those of producing cores to obtain accurate lithology and physical parameters. So, replacing the production cores with outcrop cores may become an important method to study the physical parameters of reservoirs. In this paper, the micro-velocity displacement method and saturated heavy oil method are used to study the lithology and physical property parameters of outcrop cores. The results show that compared with those of producing cores, the rock mechanics parameters of outcrop cores after high-pressure heavy oil saturation treatment are basically consistent with those of field cores. Therefore, it can be used to replace the core to study the physical parameters of rocks in special cases.

Coupled reservoir geomechanics with sand production to minimize the sanding risks in unconsolidated reservoirs

Sand production in unconsolidated reservoirs has become a cause of concern for production engineers. Issues with sand production include increased wellbore instability and surface subsidence, plugging of production liners, and potential damage to surface facilities. A field case in southeast Iraq was conducted to predict the critical drawdown pressures () at which the well can produce without sanding. A stress and sanding onset models were developed for Zubair reservoir. The results show that sanding risk occurs when rock strength is less than 7,250 psi, and the ratio of shear modulus to the bulk compressibility is less than 0.8 × 1012 psi2. As the rock strength is increased, the sand free drawdown and depletion becomes larger. The of the upper and lower sand units are 3,900 and 5,400 psi at zero depletion rate, respectively. This indicates that the sanding risk may initiate earlier at the upper sand unit. The sanding potential occurs at the perforated interval within the upper sand unit when drawdown pressures reach 2,160 psi. The sensitivity analysis shows a wide range of when the uncertainty of rock strength is considered. This study will assist in optimizing the type of completion and minimize the sanding risk in unconsolidated reservoirs.

Pore Volume Compressibility of Unconsolidated Sand Reservoirs: Insights Gained Using Laboratory-Created Sand Pack Analogs

Pore volume compressibility is a fundamental driver of production for unconsolidated sand reservoirs. Prediction of compressibility is desirable when direct measurements on core are not available. Many characteristics of reservoir sands change simultaneously. For this reason, the controls on compressibility are difficult to isolate and interpret. We present the results of compaction experiments using laboratory-created, unconsolidated sands. In these analog sands, we change one textural or mineralogical parameter at a time to investigate the influence of that parameter on the measured compaction properties. Initially, simple quartz grain packs of varying grain sizes were used. Subsequently, additional parameters were investigated, including grain packing, angularity, sorting, feldspar content, ductile grain content, small volumes of dispersed clay, and initial sample preconditioning at stress. Multiple samples of each type were created and tested. This allowed the testing to be halted at several intermediate stresses and the samples to be examined using 2D and 3D imaging and image analysis techniques. For monomineralic quartz sand packs, grain size is a principal control on compressibility. As mean size increases from 150 to 450 μm, peak compressibility increases from 6 to 24 microsips. The depletion stress at which peak compressibility occurs decreases from 8,000 to 2,500 psi. Increasing grain angularity also increases compressibility but with smaller effect. For 150-μm quartz sands, increasing the angularity resulted in an increase in compressibility from 6 microsips for round quartz to 10 microsips for angular quartz and decreased the depletion stress required to achieve peak compressibility from 8,000 to 7,000 psi. As sorting varies from well to moderately poorly sorted, compressibility decreases, and the curve broadens as a function of depletion stress. Adding small volumes of feldspar (or other minerals that cleave) increases the compressibility more than the change resulting from changes in grain size, illustrating the importance of framework grain composition. Adding similar volumes of ductile grains results in a similar increase in compressibility to that observed for feldspar. However, when the size of the ductile grains is larger than that of the associated quartz (e.g., locally derived rip-up clasts), the increase in compressibility is significantly larger. To validate the experimental work, we compare the results of uniaxial pore volume compressibility tests on laboratory-created sands with measurements made on subsurface samples of similar texture and mineralogy. Both the shape of the compressibility curves as well as the magnitude of the compressibility are successfully reproduced. We conclude that laboratory-created sands can provide reasonable proxies for estimating the compressibility of subsurface reservoirs when intact subsurface samples are not available for measurement (e.g., only percussion sidewall samples are acquired) as long as mineralogy and texture are known.

Polymer Retention Determination in Porous Media for Polymer Flooding in Unconsolidated Reservoir.

Polymer flooding is a well-established technique aimed at improved recovery factors from oilfields. Among the important parameters affecting the feasibility of a large deployment, polymer retention is one of the most critical since it directly impacts the oil bank delay and therefore the final economics of the project. This paper describes the work performed for the East-Messoyakhskoe oilfield located in Northern Siberia (Russia). A literature review was first performed to select the most appropriate methodology to assess polymer retention in unconsolidated cores at residual oil saturation. 4 polyacrylamide polymers were selected with molecular weights between 7 and 18 M Da and sulfonated monomer (ATBS) content between 0 and 5% molar. An improved 2-fronts dynamic retention method along with total organic carbon—total nitrogen analyzers were used for concentration measurement. Retention values vary between 93 and 444 The sentence could be rephrased μg/g, with the lowest given by the polymers containing ATBS, corroborating other publications on the topic. This paper also summarizes the main learnings gathered during the adaptation of laboratory procedures and paves the way for a faster and more efficient retention estimation for unconsolidated reservoirs.

Effect of Produced Sand Particles and Fines on Scale Inhibitor: A Review

Application of scale inhibitors in oil and gas production is aimed at mitigating scale blockage during production. Many experimental, mathematical, and numerical simulation modeling works have been carried out to evaluate behavior, performance, and interaction of the scale inhibitor chemicals within porous media in relation to their efficiency in solving scale problem. However, the mechanisms underpinning scale inhibitors performance are not well published. Some research works have shown theoretically that not all scale inhibitors pumped into the formation adsorb onto the formation rock. Some of the inhibitors may adsorb on produced loose sand grains or colloidal fine sand particles which float and flow within the pore spaces along with the scale inhibitor mostly in unconsolidated reservoirs This paper provides a review of research work on the effect of produced loose sand or colloidal fine particles flow on polyphosphonates and polyphosphinopolymer scale inhibitors performances during crude production.

Numerical Simulation of Channelization Near the Wellbore due to Seepage Erosion in Unconsolidated Sands during Fluid Injection

The channels may be formed in the unconsolidated sands reservoir due to formation failure during high-pressure water injection or frac-packing. Based on the continuum mechanics, a mathematical model has been established to simulate the formation process of big channels in unconsolidated sands reservoir during fluid injection. The model considers the effect of reservoir heterogeneity, solid particles erosion, and deposition. The dynamic formation process of channels around the borehole and its influencing factors are analyzed by this model. The results indicate that the seepage erosion plays a very significant role in the formation of the channels during fluid injection for the unconsolidated sands with extremely low strength. The formation of the channels is closely related to the duration of fluid injection, injection pressure, reservoir heterogeneity, formation plugging, and critical fluid velocity. The long channels are more likely to form as injection time increases. Higher injection pressure will lead to higher flow rate, thus eroding the solid particles and forming big channels. The increase of the rock strength will enhance the value of critical fluid velocity, which makes it difficult for the occurrence of erosional channelization. The near-wellbore damage of the formation will decrease the flow rate, and the preferential flow channels are less likely to be induced under the same injection pressure when compared with undamaged formation. In addition, we also found that the reservoir heterogeneity is essential to the formation of preferential flow channels. The channels are especially prone to be formed in the regions with high porosity and permeability at the initial time. The study can provide a theoretical reference for the optimal design of high-pressure water injection or frac-packing operation in the unconsolidated sands reservoir.