Unconsolidated Sandstone Reservoirs Research Articles

Damage Evaluation of Unconsolidated Sandstone Particle Migration Reservoir Based on Well–Seismic Combination

The primary factor constraining the performance of unconsolidated sandstone reservoirs is blockage from particle migration, which reduces the capacity of liquid production. By utilizing logging, seismic, core–testing, and oil–well production data, the reservoir damage induced by particle migration in the Bohai A oilfield was characterized and predicted through combined well–seismic methods. This research highlights the porosity, permeability, median grain diameter, and pore structure as the primary parameters influencing reservoir characteristics. Based on their permeability differences, reservoirs can be categorized into Type I (permeability ≥ 800 mD), Type II (400 mD < permeability < 800 mD), and Type III (permeability ≤ 400 mD). The results of the core displacement experiments revealed that, compared to their initial states, the permeability change rates for Type I and Type II reservoirs exceeded 50%, whereas the permeability change rate for Type III reservoirs surpassed 200%. Furthermore, by combining this quantitative relationship model with machine learning techniques and well–seismic methods, the distribution of permeability change rates caused by particle migration across the entire region was successfully predicted and validated against production data from three oil wells. In addition, to build a reliable deep learning model, a sensitivity analysis of the hyperparameters was conducted to determine the activation function, optimizer, learning rate, and neurons. This method enhances the prediction efficiency of reservoir permeability changes in offshore oilfields with limited coring data, providing important decision support for reservoir protection and field development.

Optimization of Injection-Production Relationship of Offshore Unconsolidated Sandstone Reservoirs Based on Inter-well Connectivity

Abstract The dynamic heterogeneity of water drive sandstone reservoir in high water cut stage is strong, which leads to the differential enrichment and distribution of remaining oil. The adjustment of injection-production relationship can effectively guide the work of stabilizing oil and controlling water. Based on the principle of inter-well connectivity, this paper comprehensively considers the geological characteristics and development dynamics, and constructs the multi-layer reservoir joint well network inter-well connectivity model. By integrating the automatic history matching and the real-time injection-production optimization algorithms, the accurate inversion of connectivity parameters and real-time optimization prediction of production dynamics are realized. Field applications in the block X demonstrated that this method resulted in an annual increase in oil production of 16,000 cubic meters and a reduction in water cut by 0.87%, showing significant enhancement in oil recovery and water control. This method can be applied to guide the adjustment of the planar injection-production structure in similar reservoirs.

Permeability prediction method of unconsolidated sandstone reservoirs using CT scanning technology and random forest model

AbstractDeveloping unconsolidated sandstone reservoirs presents a formidable challenge due to their loose formation, which often triggers alterations in pore parameters and seepage characteristics during water injection processes. This study focuses on a specific reservoir, utilizing micro-CT scanning to examine the intricate relationship between permeability and pore throat structure. Leveraging a random forest model, we establish an empirical formula tailored for high permeability reservoirs. Furthermore, we conduct in-situ CT scanning experiments across various displacement multiples to analyze the pore structure of unconsolidated sandstone cores. The derived relationship curves elucidate the positive correlations between porosity and average pore throat radius with displacement multiples, while revealing a negative correlation with tortuosity. These findings enable the formulation of quantitative formulas for permeability and displacement multiples within the studied block. Such insights prove instrumental in devising effective water injection development strategies, predicting dynamic reserves, and projecting water drive development for analogous unconsolidated sandstone reservoirs undergoing high water cut phases.

Performance of the Petroleum Reservoir Under Waterflooding at the Petrochad Field in Mangara-Chad

The Mangara petroleum field is made up of three superimposed reservoirs (C, D, E) with approximately 2500 m depth. These are unconsolidated sandstone reservoirs with an underlying active aquifer. The petrophysical properties of the reservoirs are relatively good as it’s a self-sourced unconventional reservoir based on its organic richness characteristics unconventional resource opportunity as tight carbonate reservoir. Tank pressure is approximately 2900 psi, for an average temperature of 180°F. Of the 50 wells initially drilled, 23 are currently producing. The pressure is support by 04 injector wells, and daily production is estimated at approximately 12,000 bbl/d. To maximize oil production and minimize water production, the positions of injection wells were moved, which permitted to reduce the number of producing wells from 23 to 18. The result revealed that this scheme can maintained the pressure at desired levels of 2900 psi, until year 2040 and reversed the current trend in water production, which was 14,000 bbl/d. In the predicted scenarios, cumulative production will be maintain at 25,000 bbl/d with a daily production of around 18,000bbl of oil compared to formerly figure of 7000 bbl of water until 2040.

Analysis of damage mechanisms and controlling factors of fine particle migration in unconsolidated sandstone reservoirs based on reservoir classification

AbstractParticle migration in oil and gas reservoirs is a common phenomenon in the process of oil and gas development, and is considered to be an important reason for the damage of reservoir permeability and the reduction of oil and gas productivity. The mechanism of this phenomenon includes the desorption, migration, and precipitation of particles, which eventually clogs the throat and causes reservoir damage. Therefore, it is necessary to accurately characterize the complex mechanism of particle migration and identify the main controlling factors of particle migration, which is very important for efficient oilfield development and plugging solution. First, the reservoir types are divided into three types and the pore structure models of different types of reservoirs are established. Then, computational fluid dynamics and discrete element coupling method numerical simulation and microscopic visualization of pore throat structure model were combined, to characterize the rules of particles and migration, and analyze the main controlling factors. Finally, a typical model of particle migration and clogging is established. The results show that particle size/throat and particle concentration are the key factors affecting particle plugging, and particle migration has the least effect on the permeability of Type I reservoir and the greatest damage to Type III reservoir. According to the mechanical and hydrodynamic behavior of particles in porous media, three mechanisms and six modes of particle plugging are proposed.

Stress sensitivity mechanism of pores in unconsolidated sandstone reservoir using NMR technology

Unconsolidated sandstone reservoirs exhibit low cementation strengths. With change in the effective stress state of the reservoir, stress sensitivity damage is induced. Consequently, the crude oil productivity is affected and the overall recovery efficiency of the reservoir decreases. Hence, a systematic investigation of the stress sensitivity of unconsolidated sandstone is crucial for the efficient development of unconsolidated sandstone reservoirs. This study primarily employed nuclear magnetic resonance (NMR) to conduct stress-sensitivity experiments on unconsolidated sandstone core samples. It quantitatively characterized the dynamic changes in the damage index of pore sensitivity in unconsolidated sandstone cores under different confining pressures. This research elucidated the stress sensitivity characteristics of unconsolidated sandstone cores during the process of increasing confining pressure. The results of the laboratory study indicated a positive correlation between the experimental confining pressure and stress sensitivity index of the core samples. During the initial stages of increasing confining pressure, the stress sensitivity index increased. With continued increase in the confining pressure, the stress sensitivity damage index for smaller pore throats ranged as 4.18–30.08%, whereas the stress sensitivity damage index for medium pore throats ranged as 4.15–28.45%. Stress sensitivity primarily occurred in smaller and medium pore throats during a progressive increase in the confining pressure. The degree of stress sensitivity was positively correlated with the scale of reservoir pore-throat development, with highly permeable reservoirs experiencing a greater extent of stress sensitivity damage. The statistical results provide crucial support for optimizing mining field production systems, effectively controlling reservoir damage, and achieving the efficient development of unconsolidated sandstone reservoirs.

Numerical Simulation of Hydraulic Fracture Propagation on Multilayered Formation Using Limited Entry Fracturing Technique

Hydraulic fracturing is one of the most effective stimulation methods for unconsolidated sandstone reservoirs. However, the design of hydraulic fracturing must take into account the mechanical and stress properties of different geological formations between layers. In this paper, a three-dimensional coupled fluid-solid model using the finite element method is developed to investigate multiple vertical fractures at different depths along a vertical wellbore under different geological and geomechanical conditions. The finite element model does not require further refinement of any new cracks, requiring much smaller degrees of freedom and higher computational efficiency. In addition, new elements were used to account for local pressure drop due to perforation entry friction along the vertical wellbore. Numerical simulation results indicate that hydraulic fracture connections are observed from adjacent layers. Furthermore, the low stress contrast and high Young’s modulus between the layers increases the likelihood of multiple fracture connections. Higher fluid leakage rates increase the likelihood of fracture branching, but decrease the area of fracture coverage near the wellbore. Increasing fluid viscosity is effective in improving the area of fracture coverage near the wellbore. These findings are useful for the design of hydraulic fracturing in multi-layered formations in unconsolidated sandstone formations.

Study on Stable Loose Sandstone Reservoir and Corresponding Acidizing Technology

The Sebei gas field is in the Sanhu depression area of the Qaidam Basin, which is the main gas-producing area and a key profit pillar for the Qinghai oilfield. The Sebei gas field within the Qinghai oilfield is characterized by high mud content, poor lithology, interflow between gas and water layers, and a propensity for sand production. The reservoir rocks are predominantly argillaceous siltstone with primarily argillaceous cement. These rocks are loose and tend to produce sand, which can lead to blockage. During its development, the Sebei gas field exhibited significant issues with scale formation and sand production in gas wells. Conventional acidization technologies have proven to be slow acting and may even result in adverse effects. These methods can cause loose sandstone to disperse, exacerbating sand production. Therefore, it is necessary to elucidate the mechanisms of wellbore plugging and to develop an acidizing system for plug removal that is tailored to unconsolidated sandstone reservoirs. Such a system should not only alleviate gas well plugging damage but also maintain reservoir stability and ensure efficient and sustained stimulation from acidization treatments. In this paper, the stability of unconsolidated sandstone reservoirs and the acid dissolution plugging system, along with the technological methods for stabilizing sand bodies, are studied through mineral component analysis, acid dissolution experiments, core immersion experiments, and other laboratory tests. The principle of synergistic effects between different acids is applied to achieve “high-efficiency scale dissolution and low sandstone dissolution”. Three key indicators of dispersion, sand dissolution rate, and scale dissolution rate were created. The acid plugging solution formula of “controlled dispersion and differentiated dissolution” was developed to address these indicators. Laboratory tests have shown that the sandstone is predominantly composed of quartz and clay minerals, with the latter mainly being illite. The primary constituent of the wellbore blockage scale sample is magnesium carbonate, which exhibits nearly 100% solubility in acid. By adding a stabilizer prior to acid corrosion, the core’s corrosion can be effectively mitigated, particle dispersion and migration can be controlled, and the rock structure’s stability can be maintained. Laboratory evaluations indicate that the scale dissolution rate is greater than or equal to 95%, the sand dissolution rate is below 25%, and the system achieves a differentiated corrosion effect without dispersion for 24 h. Field tests demonstrate that the new acid solution plugging removal system enhances average well production and reduces operational costs. The system effectively mitigates the challenges of substantial sand production and reservoir dispersion, thereby furnishing a theoretical foundation and practical direction for acid plugging treatments in unconsolidated sandstone gas fields.

Experimental evaluation of chemical sand stabilization and its optimization of composite sand control with squeeze gravel pack

Chemical stabilization is a viable solution for controlling the sand migration and production issues encountered in unconsolidated sandstone reservoirs. With numerous sand stabilizers available, screening the appropriate reagent and clarifying its utilization are crucial for enhancing sand control efficiency. This paper explores the impact of chemical sand stabilization on the expansion and diversification of sand production patterns and provides an experimental evaluation approach from an engineering standpoint. The evaluation experiments show that the sanding patterns may shift from collapse to a stabilized sanding cavity as the stabilizer content increases, and may remain relatively steady despite the increased flow rate under a high content of chemical sand stabilizer. Nevertheless, chemical stabilization has limited power to control unconsolidated sandstone, particularly in the early stages of fluid flushing when adequate support could not be provided, resulting in explosive sand production. Furthermore, their lifetime of efficacy in engineering applications is still insufficient. Based on the evaluation results, research on the construction method of mechanical-chemical sand control and parameter optimization including treatment range, dosage, and extrusion rate was established. The chemical stabilization screening method and mechanical-chemical design method presented in this work have been proven to be feasible through the successful application in the Gudong oilfield. The combination of chemical stabilization and squeeze gravel pack technology provides dual benefits of blocking coming sand near well and stabilizing weekly cemented sand far well, particularly for wells with extensive sanding history. It has a fair chance of helping with the engineering of sand management and production enhancement for unconsolidated sandstone reservoirs.

Study on Identification Method of Sand Production Type in Unconsolidated Sandstone Reservoir

Sand production refers to the phenomenon in the production process of an oilfield where sand grains from the formation flow into the wellbore and block the flow channels due to excessive production pressure differential, loose cementation of rocks, and other reasons. The sand production from formations is influenced by various factors and exists in multiple forms simultaneously: based on the microstructure of weakly cemented sandstone, the rock particles of sandstone are classified into skeletal sand and loose sand. However, existing research methods can only study the mechanism of sand production from loosely cemented sandstone from a macroscopic perspective. In order to achieve a refined classification of sand production types from loosely cemented sandstone during water flooding processes, this study proposes an experimental method for identifying the types of sand production from loosely cemented sandstone reservoirs. While quantitatively calculating the types of sand production from loosely cemented sandstone reservoirs, this method also fundamentally reveals the microscopic mechanism of sand production from loosely cemented sandstone reservoirs, obtaining accurate analytical results of sand production types.

Clogging caused by coupled grain migration and compaction effect during groundwater recharge for unconsolidated sandstone reservoir in groundwater-source heat pump

In unconsolidated sandstone reservoirs, presence of numerous movable grains and a complex grain size composition necessitates a clear understanding of the physical clogging process for effective groundwater recharge in groundwater-source heat pump systems. To investigate this, a series of seepage experiments was conducted under in situ stress conditions using unconsolidated sandstone samples with varying grain compositions. The clogging phenomenon arises from the combined effects of grain migration and compaction, wherein the migration of both original and secondary crushed fine-grain particles blocks the seepage channels. Notably, grain composition influences the migration and transport properties of the grains. For samples composed of smaller grains, the apparent permeability demonstrates a transition from stability to decrease. In contrast, samples with larger grains experience a skip at the stability stage and directly enter the decrease stage, with a minor exception of a slight increase observed. Furthermore, a unique failure mode characterized by diameter shrinkage in the upper part of the sample is observed due to the combined effects of grain migration and in situ stress-induced compaction. These testing results contribute to a better understanding of the clogging mechanism caused by the coupled effects of grain migration and compaction during groundwater recharge in unconsolidated sandstone reservoirs used in groundwater-source heat pump systems.

Lab Experiments for Abrasive Waterjet Perforation and Fracturing in Offshore Unconsolidated Sandstones

Multistage hydraulic fracturing has been proven to be an effective stimulation method to extract more oil from the depleted unconsolidated sandstone reservoirs in Bohai Bay, China. The offshore wellbores in this area were completed with a gravel pack screen that is much too difficult to be mechanically isolated in several stages. Hydra-jet fracturing technology has the advantages of multistage fracturing by one trip, waterjet perforation, and hydraulic isolation. The challenges of hydraulic-jet fracturing in offshore unconsolidated sandstone reservoir can be summarized as follows: the long jet distance, high filtration loss, and large pumping rate. This paper proposes full-scale experiments on the waterjet perforation of unconsolidated sandstone, waterjet penetration of screen liners and casing, and pumping pressure prediction. The results verified that multistage hydra-jet fracturing is a robust technology that can create multiple fractures in offshore unconsolidated sandstone. Lab experiments indicate that the abrasive water jet is capable to perforate the screen-casing in less than one minute with an over 10 mm diameter hole. The water jet perforates a deep and slim hole in unconsolidated sandstone by using less than 20 MPa pumping pressure. Recommended perforating parameters: maintain 7% sand concentration and perforate for 3.0 min. Reduce sand ratio to 5%, maintain 3.0 m3/min flow rate, and continue perforating for 7.0 min. The injection drop of the nozzle accounts for more than 62% of the tubing pump pressure. The recommended nozzle combinations for different fracturing flow rates are 8 × ø6 mm or 6 × ø7 mm for 2.5 m3/min and 3.0 m3/min, and 8 × ø7 mm for 3.5 m3/min and 4.0 m3/min. A one-trip-multistage hydra-jet fracturing process is recommended to be used for horizontal wells in offshore unconsolidated sandstone reservoirs.

Research on Optimal Design of Screen Out Fracturing in Unconsolidated Sandstone Reservoir Based on Fluid Solid Coupling Theory

Research on Optimal Design of Screen Out Fracturing in Unconsolidated Sandstone Reservoir Based on Fluid Solid Coupling Theory

Pore Structure and Permeability Variations during Gas Displacement in Unconsolidated Sandstone Reservoirs through CT Reconstruction Analysis

The continuous gas displacement in unconsolidated sandstone gas reservoirs will necessarily result in the pore structure and rock permeability variations, which cannot be neglected in the gas development process. However, the variations have not been comprehensively addressed yet, especially for the rock structure in pore scale. This work presented the quantitative results of pore structure in microscale and permeability variations during gas displacement in unconsolidated sandstone reservoirs through computed tomography (CT) reconstruction analysis. The results indicated that a more than 3% increase in porosity after gas displacement resulted from the enlargement of the pore and throat with a diameter of more than 20 μm and 3 μm, respectively, owing to the release and migration of clay and fine particles, in spite of the distribution frequency decline of both pore and throat with a small diameter. The pore connectivity would be enhanced by the increase of the connected pores as well as the enlargement of the pore and throat sizes. However, the pore-throat coordination number could only change with slight improvement. In terms of permeability and relative permeability changes with pore structure, the improvement of permeability after gas displacement was higher than that of porosity, and the continuous gas displacement would broaden gas-water flow region and lower irreducible water saturation and residual gas saturation, and then, the equal phase relative permeability point would shift to the right. These investigations will contribute to more accurate reserve evaluation and productivity prediction.

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.

Automated Reservoir Model Calibration Applied to a Complex Multizone Heavy Oil Field

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210185, “Automated Reservoir Model Calibration for Field-Development-Plan Evaluation Under Subsurface Uncertainty Applied to a Complex Multizone Heavy Oil Field,” by Luis D. Mendoza, Atahualpa J. Villarroel, SPE, and Maria F. Hurtado, Schlumberger, et al. The paper has not been peer reviewed. _ Fully integrated reservoir modeling for field-development optimization under subsurface uncertainty has been a major challenge so far for Rubiales, a major heavy oil field in Colombia with original oil in place of greater than 5 billion STB. An automated reservoir characterization work flow was developed to generate multiple history-matched models on the field and well level. The developed methodology and work flow successfully delivered field-development evaluation under subsurface uncertainty. The work-flow design is applicable for other fields with similar characteristics and delivery objectives. Introduction The Rubiales field is in the southeast of Puerto Gaitán, approximately 310 km from Bogotá. It is the most important oil field in Colombia in terms of extension, original volumes, and production but also is one of the country’s most complex fields, with a variety of technical challenges. Lithologically, the field is an unconsolidated sandstone reservoir with stratigraphic complexity that includes a high degree of vertical and lateral heterogeneity. Additionally, it has an infinite aquifer with tilted oil/water contact (OWC) in combination with high permeability. The produced fluid is a heavy oil (15 °API) with high water cut (approximately 95%). The current field-development plan (FDP) is based on horizontal wells as infill drilling to maintain oil production levels. A solution was designed to be tested in a specific area of the field implementing digital integration technologies. This solution included the capture of geological heterogeneities in terms of lateral and vertical continuity of the sand bodies. This digital methodology allows understanding seal and OWC effects on water production using a high-resolution model combined with an automated calibration process based on actual production as evidence. Work-Flow Design History Matching. In this project, a typical assisted history-matching process was run initially that included sensitivity and uncertainty analyses followed by an optimization algorithm. Once the sensitivity analysis was complete, the most-influential parameters were identified. Then, some variables were disabled and the uncertainty process was run with a Monte Carlo sampling considering only those parameters considered significant for the objective response. Through this process, a case ensemble with a wide-spectrum result was obtained. The next step was to focus on the optimization that was designed to improve the objective function value that should be minimized by tuning the set of input parameters remaining as active influencers. An evolutionary algorithm was implemented for the optimization that operated with three phases. In the first phase, simulation cases were distributed randomly in the search region, providing an initial ensemble. During the second phase, the better simulation cases were retained and the average objective function value was reduced. In the final phase, only the best simulation cases survived. Even when a modern algorithm was applied, the matching results were not sufficient at the well level. However, this work flow provided a good base case and insights regarding reservoir response, which are the inputs for the next stage of history matching. The further development of the history-matching methodology is detailed in the complete paper.

Supervised deep learning-based paradigm to screen the enhanced oil recovery scenarios

High oil prices and concern about limited oil reserves lead to increase interest in enhanced oil recovery (EOR). Selecting the most efficient development plan is of high interest to optimize economic cost. Hence, the main objective of this study is to construct a novel deep-learning classifier to select the best EOR method based on the reservoir’s rock and fluid properties (depth, porosity, permeability, gravity, viscosity), and temperature. Our deep learning-based classifier consists of a one-dimensional (1D) convolutional neural network, long short-term memory (LSTM), and densely connected neural network layers. The genetic algorithm has been applied to tune the hyperparameters of this hybrid classifier. The proposed classifier is developed and tested using 735 EOR projects on sandstone, unconsolidated sandstone, carbonate, and conglomerate reservoirs in more than 17 countries. Both the numerical and graphical investigations approve that the structure-tuned deep learning classifier is a reliable tool to screen the EOR scenarios and select the best one. The designed model correctly classifies training, validation, and testing examples with an accuracy of 96.82%, 84.31%, and 82.61%, respectively. It means that only 30 out of 735 available EOR projects are incorrectly identified by the proposed deep learning classifier. The model also demonstrates a small categorical cross-entropy of 0.1548 for the classification of the involved enhanced oil recovery techniques. Such a powerful classifier is required to select the most suitable EOR candidate for a given oil reservoir with limited field information.

Research and Application of Optimization Technology for High-Efficiency Fracturing and Packing Parameters of Unconsolidated Sandstone

The fracturing and filling technology is expected to meet the dual needs of production stimulation and sand control of unconsolidated sandstone reservoirs, but there is no clear guiding method for the optimization of construction parameters, which hinders its efficient development. In order to study the optimization technology of high-efficiency fracturing and packing parameters in loose sandstone, this paper takes a loose sandstone reservoir in Liaohe Oilfield as the research object and firstly studies the fracture initiation and extension laws of loose sandstone fracturing based on really well and formation data and takes this as a physical. The model explores the migration law of proppant under different working conditions. Research shows that (a) the layered fracturing is more likely to form a fracture shape that meets the dual needs of filling and production enhancement. (b) Increasing the viscosity of the sand-carrying fluid is conducive to the migration of proppant to the far end, and increasing the sand ratio will make the proppant more easily suspended in the fracture, but it is not conducive to remote migration. (c) Taking “increasing viscosity + increasing sand ratio in a small range” as the optimization idea, the ideal filling parameters are preferably 85 mPa∙s sand − carrying fluid viscosity + 15 % sand ratio . The field application results show that the daily oil production of three wells after adopting this optimization method is 2.5-3.4 times higher than that of the adjacent wells at the initial stage of production and after stable production.

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.

Technology solutions and challenges for marginal development of heavy oil fields in CuuLong basin, offshore Vietnam

The production of heavy oil at Dong Do field located in CuuLong basin is a success in the application of advanced technologies. Dong Do field is a marginal project in Vietnam, so its development requires to overcome several challenges, such as high water-cut from early stage, highly unconsolidated sandstone reservoir, flow assurance problems of sour and viscous crude oil, high power artificial lift system, and complex crude treatment at topsides, among others. Over the past decades, production technology application in heavy oil production has been widely deployed in the industry. Apart from the thermal method, the combination of gaslift and ESP technology makes the remarkable advances by enlarging the draw-down created over the conventional pumping lift in heavy oil projects. In fact, heavy oil production with a high flow rate has appeared water-coning in near wellbore region that made the water breakthrough early and water-cut increased rapidly. The pilot test of injecting diesel into heavy oil wells has been applied to producers with the positive results while significantly reduced water-cut comparing before wells shutin. This paper provides a thorough analysis of the new technologies that are applied to Dong Do field, highlighting its key difficulties and how they were resolved through a successful pilot and testing of the cutting-edge advanced solutions, improving the project reliability and thus motivating the consortium to move on to the new field. Also, the updated new heavy oil field schedule is described, highlighting the challenges to be faced during the next projects of marginal development.