Sand Production Prediction Research Articles

Simulation of Sand Production in Unconsolidated Heavy Oil Reservoirs

Previous research on sand production prediction focused on when sand will be produced during depletion based on some mechanics analyses, but the amount of sand production was ignored. Recently, more and more researchers are focussing on the simulation of heavy oil sand production processes. For an unconsolidated heavy oil reservoir which employs sand production to enhance production, the amount of sand production is of great importance, because too much sand production may cause near wellbore instability, while too little sand production may not maximize well productivity. In view of this, based on both fluid flow modelling and reservoir mechanics concepts, a coupled heavy oil/sand particulate flow/reservoir elasto-plastic deformation model is used to simulate sand production, oil production, and reservoir deformation. With this model, we can determine an optimum flow rate which will not cause near wellbore instability while maximizing well productivity.Introduction. Heavy oil sand production as an important production enhancement measure has been used in the primary development of heavy oil reservoirs in Canada for a long time.The production of sand may lead to the change of formation flow-related parameters such as permeability, porosity and mechanical parameters such as cohesion, and it also causes near wellbore stress redistribution. Thus, sand production is a very complicated process involving both fluid flow and geomechanical problems. In order to simulate the effect of sand production and productivity enhancement, simulation of the physical process needs to be done. Because of the long history of cold production, the simulation of cold production is becoming mature and a lot of excellent work has been done by experts in Canada and elsewhere around the world(1–5).Wang(1) developed a model to predict sand production in a heavy oil reservoir in Frog Lake at Lloydminster, Canada. It is believed that reservoir depletion induces stress concentrations around the wellbore, and large drawdown causes a foamy oil zone, in which large drawdown and seepage forces are created which causes sand production. A fully coupled geomechanical, foamy oil flow model was developed. Sand production is assumed to start when the effective radial stress is equal to the tensile strength. Later Wang(2) developed a coupled reservoir-geomechanical model to simulate the enhanced production phenomena in both heavy oil reservoirs (Northwestern Canada) and conventional oil reservoirs (North Sea). It is believed that the production enhancement is contributed:by the reservoir porosity and permeability improvement after a large amount of sand is produced, andby the higher mobility of the fluid due to the movement of the sand particles. Once the reservoir formation yields plastically, loose sand particles can be generated.Sand production has been postulated as a critical condition when the effective radial stress reaches the tensile strength or when the plastic strain reaches the critical plastic strain. Recently, Papamichos et al.(3) and Stavropoulou et al.(4) also provided their model to simulate sand production. Later Papamichos et al.(5) applied successfully this model to interpret sand production from a North Sea reservoir.

Simulation of Sand Production in Unconsolidated Heavy Oil Reservoirs

Abstract Previous research on sand production prediction focused on when sand will be produced during depletion based on some mechanics analyses, but the amount of sand production was ignored. Recently, more and more researchers are focussing on the simulation of heavy oil sand production processes. For an unconsolidated heavy oil reservoir which employs sand production to enhance production, the amount of sand production is of great importance, because too much sand production may cause near wellbore instability, while too little sand production may not maximize well productivity. In view of this, based on both fluid flow modelling and reservoir mechanics concepts, a coupled heavy oil/sand particulate flow/reservoir elasto-plastic deformation model is used to simulate sand production, oil production, and reservoir deformation. With this model, we can determine an optimum flow rate which will not cause near wellbore instability while maximizing well productivity. Introduction Heavy oil sand production as an important production enhancement measure has been used in the primary development of heavy oil reservoirs in Canada for a long time. The production of sand may lead to the change of formation flow-related parameters such as permeability, porosity and mechanical parameters such as cohesion, and it also causes near wellbore stress redistribution. Thus, sand production is a very complicated process involving both fluid flow and geomechanical problems. In order to simulate the effect of sand production and productivity enhancement, simulation of the physical process needs to be done. Because of the long history of cold production, the simulation of cold production is becoming mature and a lot of excellent work has been done by experts in Canada and elsewhere around the world(1–5). Wang(1) developed a model to predict sand production in a heavy oil reservoir in Frog Lake at Lloydminster, Canada. It is believed that reservoir depletion induces stress concentrations around the wellbore, and large drawdown causes a foamy oil zone, in which large drawdown and seepage forces are created which causes sand production. A fully coupled geomechanical, foamy oil flow model was developed. Sand production is assumed to start when the effective radial stress is equal to the tensile strength. Later Wang(2) developed a coupled reservoir-geomechanical model to simulate the enhanced production phenomena in both heavy oil reservoirs (Northwestern Canada) and conventional oil reservoirs (North Sea). It is believed that the production enhancement is contributed:by the reservoir porosity and permeability improvement after a large amount of sand is produced, andby the higher mobility of the fluid due to the movement of the sand particles. Once the reservoir formation yields plastically, loose sand particles can be generated. Sand production has been postulated as a critical condition when the effective radial stress reaches the tensile strength or when the plastic strain reaches the critical plastic strain. Recently, Papamichos et al.(3) and Stavropoulou et al.(4) also provided their model to simulate sand production. Later Papamichos et al.(5) applied successfully this model to interpret sand production from a North Sea reservoir.

Simple Correlation to Evaluate Mohr-Coulomb Failure Criterion Using Uniaxial Compressive Strength

The evaluation of Mohr-Coulomb failure criterion as well as other mechanical properties for reservoir rocks is essential for well planning, development and characterization of oil and gas reservoirs. This is because the understanding of the rock-stress relationship can solve many reservoir problems and avoid cost of remedial work. For example, a Mohr-Coulomb failure criterion may be used for borehole instability analysis, water injection design, production optimization techniques, compaction and sand production prediction, etc.A Mohr-Coulomb failure criterion is a function of the apparent cohesion (τ0) and the angle of internal friction (φ). The evaluation of these two parameters requires testing of many rock samples using an expensive and time-consuming triaxial testing set-up. In this study, a correlation between the apparent cohesion and the uniaxial compressive strength was developed. It is based on laboratory data of more than 200 rock samples of different types obtained from the literature. The correlation coefficient of the developed correlation equals to 0.82. Verification of the developed correlation using data from other references has shown an average error of estimation equal to 10%. Therefore, the Mohr-Coulomb failure criterion’s parameters as well as Poisson’s ratio can be estimated using the developed correlation based on fast and cheap measurements of the uniaxial compressive strength.

A New Concept of Sand Production Prediction: Theory and Laboratory Experiments

SummaryConventional theories of sand production prediction distinguish between compressive (shear) cavity (perforation, borehole) failure, induced by a combination of in-situ stress and drawdown, and tensile cavity failure, induced by the near-cavity pore pressure gradient. In this paper we show, using a global criterion for strain localization around the cavity (i.e., cavity failure), that in most cases the preference for either compressive or tensile cavity failure only depends on the cavity size and on the constitutive properties of the rock, and not on effective near-cavity stress or the pore pressure gradient. It is shown that "large" cavities (e.g., boreholes) always fail in compression rather than in tension failure. Only for sufficiently small cavities (e.g., perforations) in weak, moist sandstones, is compressive failure supressed and tensile failure possible. The above results deviate significantly from previous sand production prediction concepts. They are further supported by laboratory sand production experiments with large cavities, in which sand failure was only observed for near-cavity effective stresses above a certain threshold, independent of applied drawdown (i.e., flow rate). The experiments exhibited no correlation between the (non) occurrence of sand production and drawdown.From these results, it may be concluded that the primary role of fluid flow in sand production is the transport of loose sand (debris) resulting from compressive failure, rather than failure of the intact sandstone itself.

Mechanical Strength of Reservoir Materials: Key Information for Sand Prediction

Summary The mechanical strength of a reservoir formation is the most crucial information required for predicting sand production and recommending sand control completion. So far, the only reliable technique to obtain the formation strength quantitatively is to perform laboratory tests on core samples. The laboratory tests require substantial volumes of cores, which in most cases are not available. In this study, we present a new method to avoid this restriction. The significance of this approach is in its simplicity and efficiency in constructing a reliable mechanical failure envelope. The key results of this study, based on measurements on a variety of sandstones, are the following. A single normalized failure envelope characterizes sandstone formations. This universal curve makes it possible to construct the failure envelope for a sandstone formation from the knowledge of critical pressure. There exists a correlation between the critical pressure and the compressional wave velocity (at equivalent depths of burial). The failure envelope for a sandstone formation can then be constructed simply from compressional wave velocities. These velocities are generally accessible from conventional logging data.

Sand-Production Prediction in High-Rate Perforated and Openhole Gas Wells

This article is a synopsis of paper SPE 58721, "Sand-Production Prediction in High-Rate Perforated, and Openhole Gas Wells," Seehong Ong, Baker Atlas; Rico Ramos, Arco E&P Technology; and Ziqiong Zheng, Baker Atlas, originally presented at the 2000 SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, 23-24 February.

Stress Magnitudes from Logs: Effects of Tectonic Strains and Temperature

Summary An improved method of calibrating in-situ stress logs was validated with data from two wells. Horizontal stress profiles are useful for hydraulic fracture design, wellbore stability analysis, and sand production prediction. The industry-standard method of estimating stresses from logs is based on overburden, Poisson's ratio, and pore pressure effects and gives an estimate of minimum horizontal stress. The model proposed here adds effects of temperature and tectonics and outputs of minimum and maximum horizontal stress magnitudes, which are particularly important to the successful completion of horizontal and deviated wells. This method was validated using data collected from a GRI research well and a Mobil well. Seven microfrac stress tests in GRI's Canyon Gas Sands Well of Sutton County, Texas, provided a means of comparing the predictive capability of different methods. First, one of the seven stress tests was selected as a calibration standard for the stress log. Then the results obtained from the two calibration methods were compared to stress magnitudes from the other six stress tests. This process was repeated using each of the seven stress tests as a calibration standard and comparing predictions to the other six. In every case, the method incorporating tectonic strain and thermal effects produced significantly more accurate values. The Mobil well is located in the Lost Hills Field in California, and pre-frac treatment breakdown tests were used to calibrate a log-derived stress profile. All of the data were used simultaneously to get a best fit for the log-derived stress. The log and its fracture height growth implications compared favorably with available fracture diagnostic data, and maximum horizontal stress values were consistent with published values for a similar, nearby reservoir.

A neural approach to sand production prediction in wells

A neural approach to sand production prediction in wells

CHARACTERISING THE FULL STRESS TENSOR BASED ON OBSERVATIONS OF DRILLING-INDUCED WELLBORE FAILURES IN VERTICAL AND INCLINED BOREHOLES LEADING TO IMPROVED WELLBORE STABILITY AND PERMEABILITY PREDICTION

To minimise wellbore failures in unstable environments, knowledge of the complete stress tensor is crucial to designing optimally-stable borehole trajectories, selecting suitable mud weights, and determining appropriate casing points. Understanding how the in situ stress field interacts with the drilling and production of a well enables one to design for maximum stability and to facilitate intersecting the greatest population of hydraulically-conductive fractures for efficient production. Knowledge of the in situ stress field is also important to reduce uncertainties in sand production prediction to allow more aggressive completion designs and production schedules.A new interactive software system, Stress and Failure of Inclined Boreholes (SFIB) (Peska and Zoback, 1995a) is used to demonstrate how observations of drilling-induced compressive and tensile wellbore failures from acoustic and electrical images in vertical and inclined boreholes can be integrated with routinely-collected drilling data (leak-off and drill stem tests) to construct a well-constrained stress tensor. These techniques can also exploit wellbore image data to constrain in situ rock strength in vertical and inclined wells. This paper illustrates how to apply this knowledge to limit wellbore instability, design optimally stable wellbores, develop constraints that help mitigate problems associated with sand production, and optimise productivity of fractured reservoirs.In addition to mapping drilling-induced wellbore features, image data can also be used to determine the distribution, orientation, and apparent aperture of natural fractures and fault systems. With knowledge of the orientations and magnitudes of the in situ stresses it is possible to identify the subset of fractures that are likely to be hydraulically conductive.Examples of recent applications in the North Sea, Gulf of Mexico, California, and Puerto Rico illustrating how this integrated approach can be used in a variety of tectonic settings.

Prediction of Sand Production from a Saudi Sandstone Reservoir

Sand production is encountered in some Saudi oil fields. Six sand samples produced from different wells in a Saudi oil reservoir were obtained. Sandstone samples obtained from the same reservoir were subjected to uniaxial and triaxial failure tests. The debris produced from the sandstone samples and the six sand samples were characterized for their mineralogy using X-ray diffractometer and grain size distribution using standard sieves. Statistical analyses were employed to check whether a statistical difference between the sand samples produced from oil wells and debris collected from the failed sandstone specimens is significant or not. The critical oil rates of the Saudi oil reservoir were also calculated for different well inclination angles. Results show that, no significant statistical difference between the sand samples and debris exists at a confidence level of 95%. Two obvious failure mechanisms, splitting and shear failure, are responsible for sand production from the studied Saudi oil reservoir. The maximum sand-free production for the studied oil reservoir range from 960 to 4080 barrels per day.

Structural effects on the strength of New Zealand coal

Prediction of sand production and associated casing and tubing problems require a good understanding of failure behavior in unconsolidated and poorly consolidated sands. An experimental investigation was conducted on several fully saturated unconsolidated sand samples to determine stress states that cause sand production. Biaxial stress cycling measurements were performed at several confining pressures to demonstrate the effect of horizontal stress on formation stability. Berea sandstone samples were also tested under the same stress conditions to investigate the role of consolidation and cementation on stability. Ultrasonic wave velocity, porosity and permeability variations under biaxial stress conditions were simultaneously measured to obtain a complete comperative analysis. Failure envelopes obtained from the biaxial experiments were analyzed using Drucker-Prager failure criteria. Experimental data showed that state of stress has significant influence on the elastic and plastic deformation behavior of unconsolidated sand formations. Samples experienced inelastic and plastic deformation almost immediately with the initiation of loading. On contrary, Berea sandstone behaved almost elastically in spite of its nonlinear hysteretic behavior. It was also observed that unconsolidated sands behaved as strain hardening materials at high strain rates. The results presented here demonstrate that stability and/or failure conditions for a given formation can be predicted at all in situ stress states with limited number of experiments. The results can also be extended for fracturing unconsolidated and friable formations to inject drill cuttings into these formations for complying with the environmental regulations in an economic manner.

An investigation of mechanical, acoustic and failure properties in unconsolidated sands

Abstract Prediction of sand production and associated casing and tubing problems require a good understanding of failure behavior in unconsolidated and poorly consolidated sands. An experimental investigation was conducted on several fully saturated unconsolidated sand samples to determine stress states that cause sand production. Biaxial stress cycling measurements were performed at several confining pressures to demonstrate the effect of horizontal stress on formation stability. Berea sandstone samples were also tested under the same stress conditions to investigate the role of consolidation and cementation on stability. Ultrasonic wave velocity, porosity and permeability variations under biaxial stress conditions were simultaneously measured to obtain a complete comperative analysis. Failure envelopes obtained from the biaxial experiments were analyzed using Drucker-Prager failure criteria. Experimental data showed that state of stress has significant influence on the elastic and plastic deformation behavior of unconsolidated sand formations. Samples experienced inelastic and plastic deformation almost immediately with the initiation of loading. On contrary, Berea sandstone behaved almost elastically in spite of its nonlinear hysteretic behavior. It was also observed that unconsolidated sands behaved as strain hardening materials at high strain rates. The results presented here demonstrate that stability and/or failure conditions for a given formation can be predicted at all in situ stress states with limited number of experiments. The results can also be extended for fracturing unconsolidated and friable formations to inject drill cuttings into these formations for complying with the environmental regulations in an economic manner.

Prediction of Sand Production in Gas Wells: Methods and Gulf of Mexico Case Studies

Sand production from weak, but competent, rock as a result of high production rates is a growing concern. In unconsolidated sand, the decision to gravel pack is usually clear; however, the decision is harder in weak rock because the need for sand control often depends on the desired drawdown or production rate. Also, wells that do not initially require sand control may later become sand producers. The ability to predict at what point sand problems will occur is useful. This paper presents a method for predicting sand production in gas wells and the results of applying that method to 13 fields in the US gulf coast area. The method has since been applied extensively worldwide by Arco.

Specialists Share Knowledge of Sand-Control Methods

Five leading authorities on sand-control methods discuss specific technology applications and practices. Sand-control solutions create a variety of questions and challenges. In this question-and- answer session, a panel of five experts on the subject of sand control tackle some of the most frequently posed problems, including how to choose a sand-control method, important perforating methods and initial steps, comparing openhole completions with cased and perforated completions, causes of skin damage and how to reduce or eliminate them, challenges of horizontal sand-control completions and specific procedures, and the best way to judge the performance of a sand-control method. Mitch Cornette, SPE, with Sonat Exploration Co. in Houston, has been heavily involved with completions and sand control for 17 years. He has 19 patents in the area of sand control and production operations and is currently chairman of the Completion Engineering Assn. Derrel G. Gurley, SPE, is a petroleum engineer with more than 25 years' experience in completing wells that produce sand. He was a 1990-91 SPE Distinguished Lecturer and spoke on "Sand Control-A State-of-the-Art Review," addressing gravel-pack carrier fluids, slurries, prepacking techniques, downhole equipment, numerical model studies, matched density pack particles, and horizontal and extended-reach gravel-pack techniques. Since joining Amoco Production Research Co. in 1971, George King, SPE, has been involved in research into acidizing, damage removal, water control, sand control, horizontal well completions, all phases of chemical well stimulations, mechanical workovers, and perforating. He has completed basic research on unstable chalk and sandstone formations, foam stimulation fluids, and asphaltene sludges, and provides technical assistance as one of Amoco's specialists in several areas of stimulation and well completion. Jackie McLarty, SPE, is a technical specialist with Halliburton Energy Services. She has a BS degree in chemical engineering from Mississippi State U. and has been involved in sand-control R&D and technical services for 11 years. Jean Weingarten, SPE, is a staff engineer with Arco Alaska Inc. in Anchorage. She previously worked for Arco E&P Technology in Plano, TX, where she conducted laboratory work and analysis to develop and apply methods for predicting sand production.

Field and Laboratory Verification of Sand-Production Prediction Models

Abstract Many completion options are available to minimize sand problems. Formation-strength analysis is essential to selecting and designing the best completion method from these options. This paper addresses the accuracy of several formation-strength models to help those who plan to develop or to use these models in the future.

Sand Production Prediction

E&P Exchange Many investigators over the years have researched the causes of sand production and searched for a reliable means to predict it. Sand production prediction is important because of the safety, environmental, and operational concerns involved when produced sand particles fill and plug the wellbore, erode downhole and surface equipment, and increase operating expense. Currently, no method of sand production prediction is universally regarded as accurate and reliable within the industry. A number of prediction models have been developed to identify completions that may be expected to produce sand. Earlier attempts to develop prediction techniques included statistical models, numerical models, mechanical properties logs, sand strength logs, and core studies. Often the individual attempts to develop a predictive model were specific to the type and locale of the reservoir being studied; i.e., water production, pore pressure depletion, perforation geometry, pressure drawdown caused by skin effects, and a variety of other critical parameters were not always considered. The dilemma of an independent U.S. operator faced with a completion decision regarding sand control is not that different from the problems considered by large North Sea production companies. Quite often, the most cost-effective method to determine the need for sand control is by analogy from data collected from offset wells. Complex 3D numerical modeling in concert with extensive laboratory analysis of core and log data is not always economically practical but is the most technically correct method with an acceptable degree of accuracy when properly performed. Historically, much attention has been given to sand production prediction. The vast differences and complexities observed between the models and techniques that have been developed suggests a multitude of engineering and geologic parameters to be considered (Table 1). Morita and Boyd cataloged and analyzed five typical sand problems observed in the field that were induced by (1) unconsolidated formations, (2) water break through in weakly to moderately consolidated formations, (3) reservoir pressure depletion in relatively strong formations, (4) abnormally high lateral tectonic forces in relatively strong formations, and (5) sudden changes in flowrate (cyclic loading) or high flow rate. They developed a core-based completion guide on the premise that completion performance in a weak formation is significantly affected by near-wellbore rock strength and permeability. Morita and Boyd determined that the strength of a reservoir rock varies significantly depending on stress levels and that sandstones deform nonlinearly with the nonlinear character varying with the stress rate. In other words, sandstone failure is a dynamic process that is dependent on changing near-wellbore stresses that are affected by some combination of the 16 factors in Table 1. An evaluation of the completion at one point in time without extrapolation into the future will not accurately predict the conditions under which failure will occur. Sonic, density, and neutron logs relate the well under study to an active sand-producing well. Openhole logs must be calibrated to a known sand producer for an analogous comparison to the well being studied. The problem is that the well must be taken to the point of formation failure before the comparison can be made, and no technique exists for forecasting reservoir performance into the future. Additionally, the effects of pressure depletion, water production(multiphase flow), and additional pressure drops caused by skin effects are not considered. Wells located offshore in the Gulf of Mexico are a good example of this decision criteria. The sand production prediction technique that will be most effective for a given area is one in which field observations, laboratory experiments, and theoretical modeling are all integrated for the formation under study. References Veecken, C.A.M. et al.: "Sand Production Prediction Review:Developing an Integrated Approach," paper SPE 22792 presented at the 1991SPE Annual Technical Conference and Exhibition, Dallas, Oct. 6-9. Morita, N. et al.: "Parametric Study of Sand Production Prediction:Analytical Approach," paper SPE 16990 presented at the 1987 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 27-30. Morita, N. and Boyd, P.A.: "Typical Sand Production Problems-Case Studies and Strategies for Sand Control," paper SPE 22739 presented at the1991 SPE Annual Technical Conference and Exhibition, Dallas, Oct. 6-9. Ghalambor, A. et al.: "Predicting Sand Production in U.S. Gulf CoastWells Producing Free Water," JPT (Dec. 1989) 1336. P. 955^

Predicting Sand Production in U.S. Gulf Coast Gas Wells Producing Free Water

A study was undertaken to develop a statistical model capable of predicting the sanding of U.S. gulf coast gas wells that also produce free water. Available models predict sand production when only hydrocarbons are being produced, but none of the current models apply to gas wells when there is free-water production. Field data from gas wells and log-derived properties of reservoir rock were used to construct a usable model. This model, which differs from current models by using the previously developed dry model as an input in the statistically generated new wet model, has provided a practical tool that is based on failure criteria but validated by field data. The model presented here fits field data of water-producing gas wells better than the one currently available. When the optimum decision concerning gas production rate and the need for sand control can be made at the time of initial completion, more profit can be realized from the project. This model is intended to aid in the prevention of formation and equipment damage in gas wells.