Unconsolidated Sand Formations Research Articles

Elastic properties of unconsolidated sandstones of interest for carbon storage

AbstractUnconsolidated sandstones are attractive targets for underground storage of carbon due to their high porosity and permeability. Monitoring of injection and movement of CO2 in such formations using elastic waves requires an understanding of the acoustic properties of the sandstone. Current approaches often use the so‐called soft‐sand model in which a Hertz–Mindlin model of the acoustic properties at high porosity is mixed with the acoustic properties of the mineral phase to predict the acoustic properties over the entire porosity range. Using well‐log data from two unconsolidated sand formations of interest for CO2 storage, we discuss the limitations of this model and provide an alternative approach in which the mechanical properties of grain contacts are obtained by inversion, and the properties of infill material lying within the pore space are estimated. The formations considered are the Paluxy Formation in Kemper County, Mississippi, and the Frio Formation near Houston, Texas. The ratio of the normal to shear compliance of the grain contacts is found to be significantly less than unity for both formations. This implies that the grain contacts are more compliant in shear than in compression. However, the grain contact compliance is higher and the ratio of the normal to shear compliance is lower for the Frio example than for the Paluxy case, and this may lead to sliding at grain contacts with low shear compliance and transport of grains during fluid flow, particularly if CO2 acts to weaken any cement that may be present at the grain contacts. Such transport was suggested by Al Hosni et al. in explaining why the magnitude of the time‐lapse effect due to the injection of CO2 at the Frio CO2 injection site is greater than predicted using conventional rock physics models. A simple model of the mechanical properties of infill material lying within the pore space suggests that the bulk and shear moduli of infill material in the Paluxy case are significantly higher than the Frio case, consistent with the lower grain contact compliance in the Paluxy case.

Experimental investigation of plugging and fracturing mechanisms in unconsolidated sand reservoirs under injection of water containing suspended fine particles

Progressive plugging of the medium due to filter cake formation is considered as a major challenge during Produced Water Re-Injection (PWRI), leading decreased well injectivity during production. Field operations have shown that injectivity can be at least partially restored by fracturing the clogged medium when injecting in the frac-regime. An experimental investigation is performed to explore the effect of the injection of a suspension on the plugging and fracturing processes in an unconsolidated sand formation. The tests are performed by injecting water containing fine particles at a constant low flow rate to first clog a sand specimen (phase 1), then by increasing the flow rate until fracturing (phase 2). Experimental results exhibit a continuous increase of the injection pressure (decrease of injectivity) during phase 1 due to the formation of filter cake build-up caused by the deposition of injected solid particles. During phase 2 when the flow rate is increased, pressure drops are observed and attributed to the formation of fractures, resulting in the increase of the overall permeability of the medium. This is confirmed by post-mortem analysis of the specimens using X-ray Computed Tomography. Small radial fractures (“pseudo-cracks”) induced around the injection point are visible. They appear as localized zones of higher porosity. The effect of the confining pressure and of the suspended particles concentration on the clogging and fracturing of the medium is investigated. It is shown that the clogging process strongly depends on the concentration of particles in the injected fluid. A lower quantity of injected particles is needed to induce the same level of permeability impairment when a lower concentration is used. No significant effect of particle concentration is observed on the fracturing pressure. As with pure water injection, the fracturing pressure is proportional to the imposed confining stress. Moreover, it is observed that the clogged specimen requires a higher injection pressure to reach the frac-regime as compared to an injection scenario with pure water and no filter cake formation and that permeability recovery could be higher.

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

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

An experimental study to quantify sand production during oil recovery from unconsolidated quicksand formations

Abstract To obtain a comprehensive understanding on sand production and main factors affecting sand production in unconsolidated quicksand oil reservoirs during their production stage, the sand production processes under different conditions have been modelled. The modelling experiment was carried out on unconsolidated sand formation model made of water washed white sand, clay (kaolinite) and distilled water, by using a newly developed sanding modelling apparatus. The effects of drag force acting on the formation and formation cementation on sand production were analysed. The experimental results show sand and oil production rates both increase with the rise of drag force acting on the formation and decrease with the increase of cement content, and the sand production rate even approaches zero at high cement content. The reservoir with higher pressure is more likely to produce sand during development due to higher drag force, and drag force and effective formation stress jointly affect oil production. Therefore, the sand production rate can be estimated according to clay content, and proper sanding prevention measures can be taken correspondingly. In some cases, sand production in oil reservoirs can be much greater than that in gas reservoirs.

Dynamic Modeling of Channel Formation During Fluid Injection Into Unconsolidated Formations

SummaryInjectivity loss is a common problem in unconsolidated-sand formations. Injection of water into a poorly cemented granular medium may lead to internal erosion, and consequently formation of preferential flow paths within the medium because of channelization. Channelization in the porous medium might occur when fluid-induced stresses become locally larger than a critical threshold and small grains are dislodged and carried away; hence, porosity and permeability of the medium will evolve along the induced flow paths. Vice versa, flowback during shut-in might carry particles back to the well and cause sand accumulation inside the well, and subsequently loss of injectivity. In most cases, to maintain the injection rate, operators will increase injection pressure and pumping power. The increased injection pressure results in stress changes and possibly further changes in channel patterns around the wellbore. Experimental laboratory studies have confirmed the presence of the transition from uniform Darcy flow to a fingered-pattern flow. To predict these phenomena, a model is needed to fill this gap by predicting the formation of preferential flow paths and their evolution. A model based on the multiphase-volume-fraction concept is used to decompose porosity into mobile and immobile porosities where phases may change spatially, evolve over time, and lead to development of erosional channels depending on injection rates, viscosity, and rock properties. This model will account for both particle release and suspension deposition. By use of this model, a methodology is proposed to derive model parameters from routine injection tests by inverse analysis. The proposed model presents the characteristic behavior of unconsolidated formation during fluid injection and the possible effect of injection parameters on downhole-permeability evolution.

Creep Property Experimental Research of Offshore Unconsolidated Sand Reservoir

Unconsolidated sandstone is a kind of formation with low strength and large deformation property. Deeper unconsolidated sand formations have larger geostress and perform the plastic and rheological characteristics. After the borehole has been drilled into, this kind of sandstone will creep, which will cause some problems such as pipe stuck and casing deformation failure etc. Therefore, creep parameters of unconsolidated sandstone are critical for designing drilling fluid density and choosing casing material. Through indoor experiments, creep data of unconsolidated sandstone from Zhujiang group of X oil field in the west of South China Sea was get. The experiments results indicate that creep law of this sandstone conforms to Nishihara’s model, and the creep parameters were calculated based on experiments data. According to Nishihara’s model, using numerical simulation method, this paper analyzes the relationship of sandstone creep shrinkage rate with time of Zhujiang group reservoir sandstone and determines the drilling fluid density that ensures the safety of horizontal wells drilling, which has guiding significance for well design and drilling.

Simulation Research on the Erosion of Slotted Screen for the Unconsolidated Sand Formation

Research on the flow low in the slot of the slotted screen used in the unconsolidated sand formation is conducted with computational fluid dynamics method. Research on the erosion and corrosion of the slotted screen is presented with the calculation of flow field and the introduction of erosion model established by the Erosion and Corrosion Research Center of Tula. Moreover, the slot erosion characters and the maximum erosion with different production pressure difference and sand content are given. The result shows that: (1) the maximum value of the flow rate and the erosion appears at the horn mouth of the slotted screen; If the production pressure difference is enlarged, the amount of sand that flows into the inner of the screen will increase and the flow rate of the sand will increase sharply, which worsens the erosion of the screen; (2) the degree of the erosion of the slotted screen grows exponentially with the increase of the production pressure difference and initially increases and then decreases with the increasing of the sand content; the degree of the erosion reaches the peak value when the sand content is ten percent; and (3) the main erosion region is the middle part of the slot, and this region widens with the increasing of production pressure difference. The lower part of the screen is more damaged than the upper part.

Analytical Study to Estimate Re-entry Horizontal Well Productivity of Amara oil Field

Amara is situated south east of the city of Missan. The structure of Amara field is approximately about 9 Km long and 5 km width. This field is produced from three producing reservoirs Khasib, Mishrif and Nahr Umar. Most of the wells in this field that are producing from the main pay zone (Nahr Omar) suffer from sand production problem that was led to completely shut-in the wells due to accumulated sands in the wellbore. 
 The objective of this study is to investigate re-entry horizontal wells as a solution that may lead to minimize the well problems especially that is concern with sand problem, keeping into consideration the increasing wells productivity. 
 The production of horizontal wells can dramatically be improved by providing a greater contact of reservoir to the wellbore. Horizontal wells may also offer other advantages such as decreasing pressure drop, fluid velocities around the wellbore, minimizing water and gas coning as well as accelerated production. This may be extended to include the elimination of sand production problem from unconsolidated sand formations. Additionally, the design of horizontal wells must also includes the sand screens and/or gravel pack completion. 
 Due to limited geological and reservoir data of Amara oil field, advance analytical software was used to analyze the production history for two vertical wells AM/2 and AM/3. These wells are completely shut-in due to sand accumulation in the wellbore. The analytical solution converts the vertical well geometry into horizontal well model using same reservoir and fluid characteristics to estimate horizontal wells productivity increment for different pressure drawdowns and stimulation process. 
 The results showed that well AM/3 has greater response for production increment against the applied reservoir pressure drawdowns and stimulation activity than (well AM/2). This conclusion may led to select (well AM/3) to be much superior than (well AM/2) for eliminating sand control production.

Effective parameters for sand production in unconsolidated formations: An experimental study

Abstract Sand production during hydrocarbon production is a crucial problem in the petroleum industry. Although extensive research has been conducted in the past, there is a need to gain a better understanding of the sand production mechanisms from unconsolidated and weakly consolidated sand reservoirs, in order to develop a predictive model to quantify sand production. The main objective of this study is to examine factors influencing sand production from a screen. Such knowledge can be effectively used to minimise sand production in the field. First, a new sand production cell was designed and developed to study the sand production process. The cell constructed with a Perspex screen enables observation of the sand production process in real time through a slot simulating a wire wrapped screen or a slotted liner. The cell was then used to investigate the factors that affect sand production in unconsolidated sand formations, including the slot size, injecting gas pressure, sand particle size and moisture content. Experimental results show that sand production is highly dependent on slot size, sand particle size, moisture content and injection pressure. The rate of sand production increases with increasing injection pressure due to the increase in drag forces acting on sand formation, and excessive injection pressures may cause total collapse in sand formation. Moisture content shows a negative influence on sand production because the inter-molecular attraction between sand particles increases with increasing moisture content. These preliminary experimental results appear consistent with the findings of past research, which demonstrates that the developed cell can be effectively used to study the sand production process in geological formations. A sand production model was then developed as a function of gas injection pressure and moisture content, which can predict cumulative sand production quite accurately when the outlet is 3 mm in diameter and the mean sand particle size is between 600 µm and 850 µm.

Geomechanics of thermal viscous oil production in sandstones

Over 7 Tb of viscous oil (heavy oil, extra heavy oil, and bitumen) are trapped in sandstones or unconsolidated sand formations around the world, mainly in Canada, Venezuela, and Russia. To date, only cold flow methods and steam injection processes have achieved commercial success in accessing this immense resource. This article highlights the definitions, geology and origins, and geographical distribution of the viscous oil resources in the world, and then describes the approaches and physical mechanisms of the major commercialized viscous oil production methods being practiced around the world. Approaches to calculating thermally-induced stresses are presented, as well as discussions of thermo-mechanical issues associated with commercial thermal processes. Then, thermal, physical, and geomechanical properties of sandstone under high temperature and pressure are investigated, based on field and laboratory data. An important factor is the change in rock properties that takes place because of the large thermally-induced stresses. Finally, a practical example of thermal geomechanics effects during thermal oil production operations (example of Steam Assisted Gravity Drainage) is demonstrated, emphasizing that thermal oil production methods change reservoir rock behavior. Under elevated temperature and pressure, large changes in porosity, permeability, and compressibility occur; hence, the reservoir response evolves in time, a factor generally ignored in simulation. Whereas these geomechanical changes are largely beneficial as they tend to accelerate recovery rates, some difficult operational issues may arise, including casing shear, breach of reservoir seal, and excessive heat loss.

Technology Focus: Heavy Oil (March 2011)

Technology Focus With interest in heavy oil continuing to grow rapidly worldwide, SPE has responded to the need for increased dissemination of technical information related to the exploitation of these unconventional hydrocarbon resources. In one new initiative, SPE joined forces with the Canadian Society for Unconventional Gas to organize the 2010 Canadian Unconventional Resources and International Petroleum Conference in Calgary, in October. SPE also organized heavy-oil advanced-technology workshops and expanded heavy-oil content of regularly scheduled conferences in several Middle East countries, Russia, and China in 2010, signaling the growing importance of heavy-oil reserves to these regions. I often get asked: “What is the best recovery method to use for this heavy-oil reservoir?” The answer can vary substantially, depending on the reservoir setting and fluid properties. Therefore, as with any new field, the process of determining the preferred development strategy begins with a detailed and accurate characterization of the reservoir and fluid properties. However, in the case of heavy oil, unanticipated technical challenges are encountered routinely in accomplishing this basic exercise. For example, while tools and equipment are readily available and proved for capturing live downhole-fluid samples in conventional-oil reservoirs, this is not the case for heavy oils, especially those with in-situ viscosities exceeding several hundred centipoises, let alone thousands or tens of thousands of centipoises. Many heavy-oil reservoirs consist of unconsolidated sand formations, which also makes it difficult to acquire either fluid or undisturbed core samples and then to obtain accurate permeability and porosity data. For thermal projects, determining accurate rock and fluid properties as a function of temperature is important but is not an easy task. Specialized equipment and field-sampling/laboratory-testing techniques along with ample experience typically are required to obtain reliable data. It is also worth noting that the trend over the past few years has been to give much more attention during initial development planning to the sequencing of different enhanced-oil-recovery (EOR) strategies to maximize recovery from heavy-oil reservoirs. On the basis of the many papers written this past year related to polymer flooding of heavy-oil reservoirs, it appears that recent technological advancements and application successes have led to this becoming a viable EOR alternative for a wide range of in-situ fluid viscosities. Finally, the need for conducting pilot operations to establish actual reservoir and well performance and to validate expectations cannot be emphasized enough. Heavy Oil additional reading available at OnePetro: www.onepetro.org SPE 137639 “Thermal Properties of Formations From Core Analysis: Evolution in Measurement Methods, Equipment, and Experimental Data in Relation to Thermal EOR” by Y.A. Popov, Schlumberger, et al. SPE 134849 “In-Situ Heavy-Oil Fluid-Density and -Viscosity Determination Using Wireline Formation Testers in Carbonates Drilled With Water-Based Mud” by Ridvan Akkurt, Saudi Aramco, et al. SPE 136665 “Viscosity of Foamy Oils” by A.B. Alshmakhy, SPE, Weatherford, et al.

Polymer Flooding in Unconsolidated-Sand Formations: Fracturing and Geomechanical Considerations

Summary A study was carried out to determine the geomechanical effects of polymer flooding in an unconsolidated-sand reservoir. The work involved laboratory-scale polymer injections in unconsolidated- sand blocks to identify the injectivity mechanisms, numerical analyses for fracture prediction, and geomechanical modeling of the formation to examine the potential of shear failure and containment loss during flooding. Laboratory tests under polyaxial conditions indicate that nearwellbore fracturing and permeability increase in unconsolidated sands occur at net injection pressures limited to 2.0 MPa. These findings were applied to fracture modeling. Geomechanical modeling suggests large-scale shear failure in the sand and in the bounding shale during polymer flooding. These are expected to affect both the fracture containment and the vertical-hole integrity. Finally, fracture predictions underscore the importance of the geomechanical considerations on determining the fracture dimensions and containment. Sensitivity analyses also point to the significance of binding several key parameters for fracture prediction. These include sand shale stress contrast, fluid quality and total-suspended-solids (TSS) content, fluid rheology and effective viscosity in the formation, and the filter-cake properties in the presence of polymer. This paper provides a geomechanical perspective on the generally complex problem of polymer flooding in unconsolidated formations containing viscous oil. The work also offers some insights into the critical issues that must be examined in such situations to avoid catastrophic failures. It highlights the existing technological gaps in the current predictive capabilities.

Polymer Flooding in Unconsolidated-Sand Formations: Fracturing and Geomechanical Considerations

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 121840, ’Polymer Flooding in Unconsolidated-Sand Formations: Fracturing and Geo mechanical Considerations,’ by Mohamad Khodaverdian, SPE, Tibi Sorop, SPE, Sophie Postif, SPE, and Paul Van den Hoek, SPE, Shell E&P, prepared for the 2009 SPE Europec/EAGE Annual Conference and Exhibition, Amsterdam, 8-11 June. The paper has not been peer reviewed. A study was carried out to determine the geomechanical effects of polymer flooding in an unconsolidated-sand reservoir. The work provided a geomechanical perspective on the generally complex problem of polymer flooding unconsolidated formations containing viscous oil. The work offers insights into critical issues that must be examined in such situations to avoid catastrophic failures and highlights the existing technological gaps in the current predictive capabilities. Introduction Some unconsolidated-sand formations, both onshore and offshore, contain high-viscosity oil and could be considered for polymer flooding to improve recovery. Flooding unconsolidated sand could lead to “fracture” propagation. Although such formations typically have permeability on the order of several darcies, minute quantities of impurities and solids in the injection fluid can plug the sandface over time and lead to fracturing if the injection rate is maintained. Even in the absence of fines and solids in the fluid, the high in-situ oil viscosity and low polymer mobility could instigate fracture propagation if the injection rate is sufficiently large. Polymer flooding was proposed as an option for an offshore field to enhance sweep efficiency and production of viscous 200-cp oil. Aside from the relatively high oil viscosity, the formation characteristics include unconsolidated and highly compressible sand, relatively thick pay zone (gross nominal thickness of 100 m), and relatively small stress contrast between the sand and the caprock (potentially leading to containment loss). The primary goal of the laboratory experiments was to identify the fracturing mechanisms and establish a net propagation pressure in such formations. The findings from the laboratory tests provided empirical input (e.g., equivalent fracture toughness) for numerical simulators. Injectivity Mechanisms Previous R&D. Industry and research institutions have carried out several research projects to address injectivity and hydraulic-fracturing issues in unconsolidated sand. Investigations have focused on several types of field activities, including cuttings reinjection, hydraulic fracturing, frac packing, produced-water reinjection, and water and chemical flooding. Polymer-Injection Tests. In this work, several experiments were conducted in which polymer was injected into oil-saturated sand to investigate the injectivity mechanisms and equivalent fracture toughness under the specific field conditions. Test samples were cubic (45 cm) sand blocks.

Rock engineering systems adopted for sanding prediction in perforation tunnels

Sand production is an important issue in reservoirs with weak or unconsolidated sand formations. Production of sand not only causes several problems in maintaining wellbore integrity but also is a problem during production where damages through the tubing and surface facilities are likely to occur due to the sand grains being transported along this path. The rock engineering systems (RES), initially introduced in mining and civil related geomechanics problems, is one approach to analysing the interrelationship between different parameters involved in a rock engineering project. This is the approach that was adopted in this work to study and predict the sanding potential in perforation tunnels. Sanding mechanism in perforation tunnels during production was reviewed and all effective parameters were identified. An interaction matrix was introduced to study the sanding mechanism through the interrelation between pairs of parameters. The interaction matrix was coded using a semi-quantitative rating approach to determine the interaction between each pair of parameters. The interaction intensity and dominance of each parameter in the system were studied through the cause-effect diagram to classify the parameters. This will assist in finding a better engineering action to mitigate or eliminate instabilities. A sensitivity analysis was conducted on a data set, and major parameters playing in sand production in a perforation tunnel were identified using analytical formulae. The results of sensitivity analysis were compared with the cause-effect diagram derived from the interaction matrix. A good agreement between the two methods was observed. This shows the usefulness of RES for identifying potential sanding solutions through the interaction matrix analysis.

Modeling Hydraulic Fractures in Unconsolidated Sands

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 96246, "A New Approach to Modeling Hydraulic Fractures in Unconsolidated Sands," by Z. Zhai, SPE, and M.M. Sharma, SPE, U. of Texas at Austin, prepared for the 2005 SPE Annual Technical Conference and Exhibition, Dallas, 9-12 October. Field data show that traditional models for brittle, linear-elastic rocks do not adequately represent fracturing in poorly consolidated rocks. A model was developed for describing the propagation of "fractures" in unconsolidated sands. The model departs radically from current models in that brittle-rock fracture mechanics is not used. Instead, the propagation of pore pressure is computed, and the porosity and permeability of the sand are specified as functions of the effective stress. This region of enhanced porosity defines a "fracture" in unconsolidated sands. The physics of creation and propagation of this oriented high-permeability zone is modeled. Introduction The application of frac packs in poorly consolidated reservoirs has been effective to prevent sanding problems. In conventional hydraulic-fracture simulations, to which linear-elastic fracture mechanics (LEFM) is applied, fracture initiation and propagation are governed by in-situ stresses, fracture toughness, tip dilatancy, and the process zone. Unlike competent formations, unconsolidated-sand beds have little or no tensile strength. LEFM is adequate for hard rocks, but the fracture-geometry predictions fall short when applied to fracturing soft rocks. For example, when using classical fracture models for simulating this process, it has been reported that millions of barrels of solid-waste slurry can be injected easily into soft formations over a period of several years. To accommodate such a large volume of solids, fracture lengths of several miles would be required, even with fractures that are several centimeters wide. Experimental and simulation studies identified mechanisms of fracture propagation and initiation in unconsolidated-sand formations. Many of those studies rely on classical brittle-rock fracture mechanics and in some cases do not account for shear failure. Permeability anisotropy induced by in-situ stresses is not considered. An approach to modeling the mechanical behavior of unconsolidated sands that are subjected to injection of water-based slurries is detailed in the full-length paper. Model for Stress Distribution Around an Injection Well To study fracture initiation and propagation, the effective-stress distribution around the well must be obtained and then the permeability and porosity updated in accordance with the appropriate constitutive relationships. The stresses around the wellbore can be divided into three parts.Stresses induced by far-field, in-situ stresses.Stresses induced by wellbore pressure.Flow-induced stresses (poroelastic stresses). On the basis of stress distribution, the anisotropic stress tensor can be determined as well as where and when tensile or shear failure occurs. This approach has been applied widely to wellbore-stability problems for homogeneous isotropic rocks. In this paper, the stress distribution is coupled with the pore pressure, and the model is applied to hydraulic-fracturing problems in unconsolidated sands. This iterative, coupled program was developed to calculate the pore pressure, stress/strain distribution, porosity, and permeability in the formation.

A New Methodology for Modelling of Sand Wormholes in Field Scale Thermal Simulation

Abstract Sand wormholes created by the concurrent production of sand and heavy oil are instrumental in improving oil rates and ultimate recovery. The wormholes form high permeability conduits for flow of oil and more sand. The wormholes may extend several hundred metres away from each well and connect with other wells' wormholes. Efforts have been made to predict the wormhole network based on growth of each wormhole's tip. In this paper, we use a fractal geostatistical method to pregenerate the wormhole network. This wormhole network is then incorporated into a full field thermal simulation model. A dual porosity-dual permeability grid is used, one for the reservoir pay and one for the wormhole network. The wormhole grid cells have the same pore volume as the wormholes and a sparse network structure. With this wormhole representation in the simulation model, we were able to match thermal responses of cold production wells from a steam injection pilot due to the wormholes conducting hot fluid from the steam injectors. As a result, this modelling concept for wormholes may be used to investigate post cold production thermal recovery methods as well as for thinner reservoirs not suitable for Steam Assisted Gravity Drainage (SAGD) where the wormholes may act as natural horizontal wells. Introduction Sand production occurs with heavy oil production in unconsolidated sand formations. If sand production is stopped with screens or filters, this often results in near total loss of production from the well. With the use of progressive cavity pumps, sand production can be encouraged, resulting in sand cuts that can be as high as 30 – 40% initially before dropping to about 5%. The production of sand results in open holes, whimsically called wormholes, that stretch far into the formation away from the well. The productivity of the well rises from the average 4 to 5 m3/d to as high as 15 to 20 m3/d as the wormholes form high permeability conduits for flow of oil and more sand. This production process is called Cold Heavy Oil Production with Sand or CHOPS. Many papers have been published on the mechanics of sand wormhole development. Recently, Y. Wang and C. Chen(1) describe a reservoir model coupled with a detailed wormhole propagation model. The model also incorporates slurry transport with three phase fluid flow. This appears to be a single well model. Research work at the Alberta Research Council on modelling cold production was published by Sawatzky et al.(2). They provide a review of cold production technology as well as their modelling efforts in combining a comprehensive sand production with a fluid flow simulator. It would appear that this too was a single well model predicting the development of wormholes from a well using criterion for sand failure at the tip of a wormhole. These two papers also list extensive bibliographies which will not be repeated here. We are, however, more concerned with the effect of a developed network of wormholes on recovery from a reservoir than with trying to predict the growth of each wormhole based on stresses at its tip.

Perforating Unconsolidated Sands: An Experimental and Theoretical Investigation

Summary This paper describes the experiments and modeling undertaken to develop a perforating strategy for unconsolidated sand formations. The experimental program consists of single-shot perforations in cylindrical samples of three sizes (4-, 7-, and 10.5-in. diameters) of unconsolidated sand saturated with kerosene at residual brine saturation and placed under a high effective stress in a pressure vessel. The amount of sand produced during perforating, as well as that produced during post-shot flow, is measured, and a video probe is used to observe post-shot sand production. Computerized tomography (CT) scan equipment is used to map the geometry of the cavity. The sand features behind the casing are examined and interpreted, providing essential insights into the interaction of the charge with the sand sample. A theoretical model of the failure mode of unconsolidated sands has been developed that supports the observations. The main results so far from this study are as follows. Perforating does not generate a tunnel in unconsolidated sands. The intense pressures set up by shaped-charge penetration in the weak sand sample fluidize it and cause the initial tunnel to collapse. Production flow creates a dilated zone around the tunnel entrance. At a critical flow rate, a large volume of sand is produced and the sample collapses. This occurs when flowing out of a hole in an unperforated sample as well. The implications of these results for future work and for field applications are also addressed here.

Challenges, Accomplishments, and Recent Developments in Gravel Packing

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized to be experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction Techniques used for sand control include restricted hydrocarbon production, in-situ consolidation, gravel packing, high-rate water packing, frac packing, fracturing without screens, and drilling horizontal wells completed with screens. Frac packing, high-rate water packing, and horizontal completions have been the most widely used of these techniques in recent years. Fracturing without screens, frac packing, and horizontal drilling all aim at reducing drawdown and/or increasing production rates by decreasing velocities in the formation with a larger flow area. The increased flow area also makes these methods more tolerant to formation and completion damage. Achieving long-term sand control without impairing well productivity has been a challenging task from both a technical and an economic perspective for many years in almost all major oil- and gas-producing regions of the world. Because this article is a review of the challenges, accomplishments, and recent developments in gravel packing, we limit our discussion to treatments below fracturing pressure by assuming that exceeding the fracturing pressure is undesirable for technical reasons. It is not our intent to suggest that gravel packing is the preferred sand-control method. All methods for sand control have their own applications and value in the industry. We first discuss recent developments and challenges in gravel, screen, and carrier-fluid areas and follow this by a discussion of gravel packing in cased holes, where major accomplishments have been introduction of combined processes that not only reduce completion costs but also improve productivity. Next, were view openhole gravel packing, primarily for highly deviated or horizontal wells because this is where most openhole gravel-packing applications have been. Finally, we draw conclusions and highlight the accomplishments and remaining challenges. Ideal Gravel-Pack Completion From a technical standpoint, an ideal gravel-pack completion accomplishes the following objectives.Complete packing, with a properly sized high-permeability gravel, of allvoid spaces between the screen and casing and perforations or between the screen and the open hole.Clear interface between the formation sand and gravel, with nomixing/invasion of formation material with/into the gravel pack during placement and during production throughout the life of the well.No invasion of the matrix with damaging material (e.g., unfiltered or incompatible brines, polymers, crushed gravel).No reduced-permeability section between the formation sand and the gravelpack (e.g., drilling-fluid filter cake in open holes or crushed zone in cased and perforated holes).No residuals from the carrier fluid and/or fluid-loss pills (e.g., polymers and bridging agents in gravel pack). Particular attention also must be given to prevention of screen plugging while running the screens in hole (discussed later). Obtaining a technically ideal gravel pack as described has been a major challenge, and all objectives have not been achieved under all circumstances. Furthermore, achieving this type of completion may not always be necessary, depending on cost/benefit analysis. For example, openhole horizontal completions sometimes can tolerate high levels of damage with little impact on productivity. In such cases, incremental production resulting from a cleanup treatment needs to be weighed vs. cost. Regardless of the type of completion (open or cased), the first potential source of formation damage is the drilling fluid. In recent years, with the increased applications of horizontal wells, substantial effort has been devoted to formulating reservoir drilling fluids (RDF's) that form a tight filter cake with minimal particle and polymer invasion into the matrix and that contain soluble (in acid, water, or oil) bridging agents. Proper RDF selection typically is considered to be less of an issue in cased holes because the damaged region is believed to be bypassed by the perforations; however, this may not be true in unconsolidated sand formations because perforation collapse is highly likely.

Is It Futile to Measure Relative Permeability For Heavy Oil Reservoirs?

Abstract The importance of relative permeability curves in calculations of reservoir performance can hardly be overstated. Both oilwater and oil-gas two-phase relative permeability functions are crucial parts of the input data for heavy oil reservoir simulation studies of primary depletion and thermal recovery processes. The simulation results are often very sensitive to small changes in the relative permeability curves. Therefore, substantial effort and resources are spent in obtaining laboratory measurements of relative permeability. However, as is often the case, when the history match is unsatisfactory, the parameter that is most likely to be adjusted is the relative permeability. Is it, then, futile to measure relative permeability in heavy oil systems? This paper attempts to answer this question by examining the theoretical and experimental problems in applying conventional relative permeability concepts and methods to heavy oil systems. The experimental difficulties can start in the very first step of obtaining a representative core sample. The core damage occurring in coring and core handling operations can have significant effect on the measured relative permeability. A brief review of how heavy oil/water (or heavy oil/gas) relative permeability of unconsolidated sand formations is measured in the laboratory, is presented with focus on possible sources of errors. The role of viscous fingering in relative permeability measurements and the conditions under which the laboratory measurements fail to represent the field behaviour are discussed. It is shown that the laws governing simultaneous flow of heavy oil and water (or heavy oil and gas) through porous media have not yet been clearly formulated. The flow description based on the relative permeability concept, although not as convenient and powerful as it is in the conventional oil systems, is still the best available alternative. Introduction The concept of relative permeability stems from the empirical extension of Darcy's law to two-phase (or multi-phase) flow in porous media. Relative permeability, by definition, is the ratio of the effective permeability of a porous medium for a given fluid and a base value of permeability, which is often the absolute permeability of the medium. Thus the relative permeability is a measure of the fractional loss of conductivity for a given fluid due to the presence of other immiscible fluids in the porous medium. The two-phase relative permeabilities are assumed to depend on saturation, saturation history, wettability and pore structure but not on fluid viscosities, densities or flow rates. Bear(1) examined the experimental and theoretical evidence supporting this concept and concluded that it was a good approximation for all practical purposes. This conclusion is also supported by the extensive, and generally successful, application of this flow model in reservoir engineering calculations. Numerical simulation of reservoir processes requires relative permeability curves among other data. These curves are generally estimated from laboratory experiments involving two-phase flow in small samples of the reservoir rock. In view of the heterogeneous nature of petroleum reservoirs, the application of the experimental data measured on a small sample of the rock to represent the fluid flow behaviour of the reservoir represents a leap of faith.

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.