Kazakhstan owns one of the largest global oil reserves (~3%). This paper aims at investigating the challenges and potentials for production from weakly-consolidated and unconsolidated oil sandstone reserves in Kazakhstan. We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves, in Kazakhstan, were studied in terms of the depth, pay-zone thickness, viscosity, particle size distribution, clay content, porosity, permeability, gas cap, bottom water, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, geological condition, including the existing structures, layers and formations were addressed for different reserves. Weakly consolidated heavy oil reserves in shallow depths (less than 500 m) with oil viscosity around 500 cP and thin pay zones (less than 10 m) have been successfully produced using cold methods, however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical in comparison to the similar cases in North America. The complicated tectonic history, necessitates the geomechanical models to strategize the sand control especially in cased and perforated completion. These models are usually avoided in North America due to the less problematic conditions. Further investigation has shown that Inflow Control Devices (ICDs) could be utilized to limit the water breakthrough, as water coning is a common problem, which initiates and intensifies the sanding. This paper provides a review on challenges and potentials for sand control and sand management in heavy oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.

Many gas wells in Adriatic Sea are suffering from both water and sand production. An original sand control polymer technology has been successfully implemented and has proven to be an efficient way to stop sand production and thus maintain gas well under steady production. In many wells, a reduction of water production was observed as side effect. Nevertheless, the main objective remained sand control and not water control. The present paper describes a polymer treatment performed in an offshore well equipped with sand control gravel-pack downhole completion. This well was suffering of high level of water production inducing a severe decline in gas production. The preparation of the treatment consisted of lab coreflood tests aiming at checking the behavior of the selected polymer (P-321) in actual reservoir conditions. The product was shown to have good injectivity and to strongly adsorb on the reservoir rock. Moreover, it has good RPM properties, inducing a strong reduction in water relative permeability while preserving gas relative permeability. The treatment proceeded in the bullhead mode, i.e. through the gravel pack. The polymer was followed by a Nitrogen postflush to squeeze the product deep in the formation and help restarting the well. Immediately after treatment, gas rate increased while water rate levelled off. Both gas rate and GWR (Gas Water Ratio) stopped declining and remained at same level for two years. After two years, the estimated additional gas production was 13,330 KSCM and the well keeps flowing steadily instead to be probably shut in if it had followed its initial decline trend.

Although a well has hundreds of perforations, a single perforation is normally used for perforation interaction analysis assuming the perforations are shot symmetrically and the stress state around a perforation is symmetric in both vertical and horizontal directions. However, for the single/double spiral perforations shot in inclined wells, no vertical and horizontal symmetry surfaces exist. Required elements for multi-perforation model are more than 10,000, which results in complex mesh generation and long computation time. This study investigates perforation interaction to find the optimum perforation design which yields the highest productivity while maintaining mechanical stability.

A new approach for estimating sand production through gravel packs is presented in this paper. The approach involves two steps: (a) evaluating the pore throat size distribution (PoSD) of a gravel pack and (b) estimating sand production through the gravel pack using an analytical model. Results of the analytical model are compared with sand production data obtained from lab experiments and Monte Carlo simulations. The PoSD of a gravel pack is evaluated using the discrete element method (DEM). The process includes generating a random close packing of gravel based on the gravel particle size distribution (PSD) and evaluating the pore throat size distribution (PoSD) in each layer of the gravel pack. The evaluated gravel pack PoSD is then used to compute the filter efficiency of the pack for various formation sand sizes. Sand production through the gravel pack is predicted analytically by applying the filter efficiency data to any given formation PSD under the assumption that straining is the dominant sand-retention mechanism for a gravel pack. Results from DEM simulations show that the smallest and largest pore throats in a gravel pack are typically sized around 1/9 and 1/4.8 to 1/5.5 of the effective gravel diameter ( D eff ), respectively. These observations suggest that any formation sand grains larger than 1/5.5 D eff will be retained near the sand-gravel interface, i.e. within 10 layers of gravel from the sand-gravel interface. Furthermore, the gravel pack alone cannot retain any formation sand smaller than 1/9 D eff for a typical thickness of the gravel pack. A secondary pack formed by retained formation sand is essential for effective sand retention in such cases. Increasing gravel packing thickness primarily improves the retention of sand sized between 1/5.5 to 1/9 D eff , and the effect is insignificant for sand out of this size range. Finally, the analytically estimated sand production using DEM-evaluated PoSDs agrees reasonably well with sand production data obtained from lab experiments and Monte Carlo simulations. The proposed approach provides a time and cost-efficient way to predict the effectiveness of a gravel pack for any given formation sand size distribution. The approach accounts for the gravel particle size distribution and the thickness of the annular gravel pack. Application of this new approach can improve the reliability of sand control completions by better justifying a gravel design, specifically in reservoir sands with poor uniformity (i.e., high-fines).

A pressure pulse, known as a water hammer, can occur immediately after water injection wells are shut-in for emergency or operational reasons. Large pressure pulses may cause wellbore integrity problems such as sand-face failure and sand production. We propose a new workflow to simulate water hammer events, the resulting wellbore failure and sand production in water injectors. Based on the results of this workflow, recommendations are made for wellbore design and shut-in protocols for water injection wells. The results presented in this paper, for the first time, allow us to quantitatively understand the role of well shut-downs and subsequent water hammer pressures on sand production. The failure of unconsolidated sands near the wellbore is affected by water hammer events, their amplitude, period, and attenuation. If a water hammer event occurs during shut-in of water injectors, the extent of the sand failure becomes larger and the failure zone continues to propagate along the stress concentration direction. The simulation results clearly show which parameters are important and suggest changes to well operations such as proper shut-in protocols that help to minimize the possibility of sand production. The results also suggest ways in which injectors can be designed to minimize the impact of water hammer events.

This paper presents how the sand control and management strategies of an oil field were optimised after multiple well failures between 2014 and 2016. It describes the impact of the new strategies on oil production and net present value. Field E is a sandstone field with oil and gas-cap gas at initial conditions, and has been developed with 5 production wells, 2 water injection wells, and 2 gas injection wells. The first nine wells were drilled from an offshore platform and completed with sand screens between 2012 and 2013. Production commenced in late 2013, and by the end of 2016, multiple sanding events had been reported and four of the five production wells had died. The asset team was tasked with diagnosing the cause of the well failures and developing solutions. Pressure data suggested that three of the failed wells had tubing restrictions, and the fourth failed well had a blockage upstream of the BHP gauge. The sand count data suggested significant sand production prior to well failures, and sand was also recovered from the separators. Pressure transient analysis suggested that the field had a lower permeability than the pre-development estimate, and higher pressure drawdowns were needed to produce economic oil rates from the field. It was concluded that the well failures were most likely caused by the high pressure drawdowns, which pulled sand from the reservoirs, and led to screen breakage in at least two wells and screen plugging in one well. A decision was made to re-drill the failed wells in 2016, and complete them with frac-pack sand control solutions. The drilling and production performance of the first two new wells are presented in this paper. The asset team also implemented a new and improved sand management strategy in Field E. This paper presents the lessons learnt from a new oil field impacted by sand production. It also outlines practical well diagnosis and sand management strategies, and presents simple methods of preserving well integrity and cash flow in oil fields struggling to manage sand production in a 40 USD/barrel oil price environment.

Sand production is not usually considered a major concern during the injection phase in injection wells. However, well shut-in for service requirements or sudden pump failure, hence the backflow towards the wellbore and potential generation of water hammer pressure pulsing, can lead to massive sand production under favorable conditions. With the aim of sanding prevention, this paper examines the design criteria for standalone screens (SAS) in injection wells using a novel sand control testing facility. This paper presents a new large-scale sand retention testing (SRT) facility to simulate the effect of pressure pulsation and backflow in injection wells on the sand control performance of SAS. The SRT facility can be used in the selection of the best sand control method for injector wells. It can be also used to provide further understanding on the impact of formation damage on well injectivity decline, as well as study the effect of water hammer pressure pulsation on sand production in injection wells. Test results show a rapid fall off in the pressure and drastically high backflow rates due to the sudden shut-in. Higher pressure drops are observed to result in a greater backflow volume and a longer backflow period. Results also show that the slot width has a drastic influence on the sanding performance of the screen. Testing observations, for the studied PSD, indicate that the injection well requires narrower slots 1.4 D10 to meet the sand production requirements due to a high fluidization potential in the near-screen zone. Higher flow velocities during the backflow period and the tossing effect caused by the pressure waves increase the sanding potential. The produced sand during the backflow period, is observed to mainly relate to the ratio of the slot width to the mean formation grain size. It is observed that higher effective stresses around the screen work towards stabilizing the sand bridges and reducing the amount of produced sand. This paper presents a new experimental test facility for the sand control type selection and evaluation for injection wells with the aim of limiting the amount of produced sand and sustaining the wellbore injectivity. The proposed testing facility allows the performance comparison of different sand control devices and designs.

Multi-layered metal-mesh screens (MMSs) are widely used as stand-alone screens for sand control in unconsolidated formations. The nominal rating of such screens is usually based on the specifications of the filter layer. It is often found that screens with the same filter layer nominal rating perform differently. It is shown in this study that the primary reason for this is that the sand retention performance of multi-layered MMSs is a strong function of not only the filter layer but also the protection and the support layers. This paper presents a systematic study that shows how the overlap between different mesh layers, the alignment of the protection and support layers, and the relative pore size ratio, defined as the ratio of pore size of the protection/support layer to that of the filter layer, have a large impact on the sand retention performance of a MMS. The pore size distribution (PoSD) of multi-layered plain square mesh (PSM) and plain Dutch weave (PDW) screens are calculated using a novel numerical technique. Influences of screen-sintering, coupon-sampling, and screen designs on PoSD of a screen are modeled by varying the layer-overlap, shifting the layer-alignment, and modifying the design of the protection and support layers. The PoSD data is used as an input into a validated analytical model for evaluating sand production of PSM screens in slurry type sand retention tests (SRTs) for screen design optimization. For PSM screens, the results show that the PoSD of a multi-layered screen can be very different from the PoSD of the filter layer. In general, a decrease in sand production with an increase in layer-overlap is observed; the trend exists irrespective of how mesh layers are aligned. A change in mesh alignment is found to cause a variation in sand production even with the same filter layer pore size and layer-overlap. The nominal rating of the filter layer of a multi-layered PSM screen should be used to estimate sand production only when the pore sizes of the protection and support layers are much larger than the pore size of the filter layer. For PDW screens, layer-overlap is shown to dominate the screen performance by affecting the filter layer pore size. PoSD of a PDW screen is found to be less affected by variations in layer-alignment and relative pore size ratio. This study clearly shows that layer-overlap, layer-alignment, and relative pore size ratio between mesh layers can have a significant impact on the sand retention performance of a multi-layered MMS. These factors are seldom considered when selecting a screen. As such widely different screen performances can be expected for screens with the same nominal screen rating. Our results have a direct bearing on how MMSs are manufactured, selected, and specified. Increasing the relative pore size ratio appears to be a promising screen-design approach for obtaining consistent screen performance for multi-layered MMSs.

The primary goal of screen design for steam assisted gravity drainage (SAGD) operations is to prevent the entrance of the poorly or unconsolidated sand into the production flow stream, which could cause serious damages to the downhole/surface facilities. Current screen design approach fits one screen opening size for the entire length of the well, which leads to a conservative screen opening to avoid sand production along the well. This study introduces a new approach to design the screen opening, considering different opening sizes along the horizontal well. The proposed workflow in designing the optimum screen opening relies on well logs and core analysis to map the grain size distribution within reservoir through a geostatistical approach. Considering the horizontal well path and the changes in liner length due to installation and thermal loads, we design the screen aperture size to optimize the screen selection based on sand facies present in different sections of the wellbore. This enables us to provide different screen opening for different sand facies along the horizontal well. The new approach provides a more detailed design for screen opening for the horizontal well according to the sand size distribution within the reservoir instead of trying to fit one opening size for the entire horizontal section. It also considers the thermal expansion of the joints. This approach designs the screen opening for different sand facies along the horizontal well in a way which obtains the highest productivity and lowest produced sand. This paper provides a novel workflow for the design and optimization of screen for horizontal wells, which could be used to optimize the design of different standalone screens such as slotted liner, precise punch screen (PPS) and wire wrapped screen (WWS).

The integrity of sand control method is often compromised as wells get older and the field becomes more mature. An operator in East Malaysia pursued a cost-effective alternative remedial sand-control solution to restore the functionality of its sand control completion and provide unhindered oil production in a well. The well, located offshore Sarawak Malaysia, was a single string oil producer completed in 1987 with gravel pack and screens. It was a producing well for several years until the gravel pack completion failed and the well started to produce excessive sand. The well was beaned down (BD) to achieve an acceptable sand production limit by the operator of below 15 pound per thousand barrels (pptb). The initial remedial sand control measure was to install a thru-tubing screen, hung inside the production tubing. The thru-tubing screen failed to control the formation sand and a second 200 micron thru tubing screen was installed. That screen managed to control the sand production at acceptable levels but induced significant pressure drop, which reduced the oil production from the optimum level of production. Workover (WO) operations would involve pulling the existing completion, and re-gravel packing the zone would be costly. In addition to cost, induced mechanical skin in a gravel pack might not be lower than thru-tubing screen application. Chemical consolidation treatments using solvent-based resins historically have been used successfully as alternatives to remedial sand control, although their application, has typically been limited to short intervals. An aqueous based consolidation resin was developed that provides some advantages compared to conventional solvent based resin systems. The aqueous based resin system uses an internally cured water-based epoxy resin. Unlike the solvent based resin systems, which have a low flash point, the aqueous base consolidation resin system is not flammable. It is safer and less complex operationally. The consolidation-fluid mix can also be foamed for diversion purposes to treat wells with relatively large variations in permeability over longer zones compared to the solvent based resins. This paper describes the treatment background, engineering approach, laboratory testing, fluid design stages, quality assurance/quality control (QA/QC) procedures, and the treatment execution for the chosen well. The field trial showed no sand was produced after treatment. In fact, the production rate was twice that of the production rate with the thru tubing screen in place. The promising result from this well creates new opportunities for simple, environmentally acceptable, and cost-effective remedial sand-control solutions for the operator.

Sand particle size distributions (PSD) are used for various purposes in sand control: decision between various sand control techniques, sizing of the filter media (sand screens and/or gravel packs) through either rules of thumb or physical experiments or theoretical models. PSD of formation sand samples are also often used to generate "simulated" formation sand for laboratory experiments. The two most commonly used techniques for PSD measurements are sieve and laser, while some engineers use one technique for no obvious or justifiable reasons, others use both techniques for measurements and don't know what to do with the data when significant differences exist in PSDs obtained from each technique. Although the inherent limitations of, and the differences between, these two techniques as well as other factors impacting the measurements are well known, a systematic study as to what is relevant to sand control and why, is lacking. In this paper, we critically review the current practices in PSD determination, use (and misuse) of the information obtained from these measurements, propose a methodology towards determining what is relevant, when and why, and present initial experimental results that support our conclusions.

A three-dimensional numerical model was developed to simulate the stability of wellbore and perforation tunnels completed in weak sandstone formations. Post-yield mechanical behavior of granular materials is incorporated in the model to study the mechanical instabilities associated with such completions. Fluid flow calculations are also incorporated in which they are computationally coupled with the mechanical calculations to generate pore pressure and stress distribution in the sand matrix. In addition, the model presented here extends the use of the sand erosion criterion developed by Kim (2010) in order to compute the mass of the produced sand. It has been shown through field experience that sanding is influenced by several factors such as completion geometry, wellbore inclination, perforation orientation, and in-situ stress anisotropy. The developed model is capable of simulating the impact of these factors and assessing their sanding risk through advanced modeling and meshing techniques. The model can be utilized accordingly to design a wellbore completion that maximizes the mechanical stability and reduces the sand production rate. Different production and operational conditions can also be simulated to determine the onset of sand production and the critical drawdown pressure. Results obtained from the model shows that vertical wellbores produce less sand in regions where the overburden stress is the maximum in-situ stress. In horizontal wellbores, vertically oriented perforations are more stable than horizontally oriented perforations and can withstand higher drawdown before sand is produced. A wellbore model with multiple perforations was also constructed to investigate the effect of mechanical and hydraulic interference from adjacent perforations on the evolution of plastic strain. It was shown that perforation spacing has an influence on both the magnitude the spatial spread of the plastified zone. By combining the effects of phasing angle, perforation density, and wellbore diameter, the model is capable of determining the completion configuration with the least sanding risk.

Acidizing in sandstone formations is a real challenge for the industry. Fines migration, sand production, and additional damages due to precipitation are some of the common concerns with sandstone treatments. Furthermore, the complexities of sandstone formations require a mixture of acids and loadings of many additives. The environmentally friendly chelating agent, glutamic acid N,N-diacetic acid, GLDA, was successfully used to stimulate deep gas wells in carbonate reservoirs. It was extensively tested in the lab to stimulate sandstone cores with various mineralogies. Significant permeability improvements were reported in our previous papers over a wide range of conditions. In this paper, we evaluate the results of the first field application with a fluid based on this chelating agent to acidize an offshore, sour oil well in a sandstone reservoir. The field treatment included pumping a preflush of xylene to remove oil residues and any possible asphaltene deposited in the wellbore area, followed by the main stage that contained 25 wt% GLDA, a corrosion inhibitor, and a water wetting surfactant. The treatment fluids were displaced into the formation by pumping diesel. Following the treatment, the treatment fluids were allowed to soak for 6 hours, then the well was put on production, and samples of flowback fluids were collected. The concentrations of key cations were determined using ICP, and the chelate concentration was measured utilizing a titration method using ferric chloride solutions. Corrosion tests conducted on low carbon steel tubulars indicated that this chelate has low corrosion rates under bottomhole conditions. No inhibitor intensifier was needed. The treatment was applied in the field without encountering any operational problems. A significant gain in oil production was achieved without adversely impacting the water cut, causing sand production, or fines migration. Analysis of flowback samples confirmed the ability of the chelating agent solution to dissolve various types of carbonates, oxides, and sulfides, while keeping the dissolved species in solution without causing unwanted precipitation. Unlike previous treatments conducted on this well, where 15 wt% HCl or 13.5/1.5 HCL/HF acids were used, the concentrations of iron and manganese in the flowback samples were negligible, confirming the very low corrosion rates of well tubulars when using GLDA solutions.

Sand production caused the abandonment of two production wells out of four in a gas field located in the Netherlands sector of the North Sea. The forced two abandoned wells due severe sand production accounted for 75% of total gas production from the field. The loss production was unexpected. This paper describes how geomechanics was applied to develop a screenless completion design for one well, and cased-hole with gravel packs for three others, to re-establish economic sand-free production rates for the field. A geomechanics study of the reservoir sections of the abandoned wells examined the mechanical properties, including rock strength and plasticity, as well as the state of stress acting on the producing sections. The study predicted the sanding history of both wells accurately. Modelling indicated that a thin sand layer with low rock strength was the main contributor to the overall sand production. This was later validated with a Downhole Sand Detector Tool. The modelling also indicated that sand production was likely from other, stronger sections of the reservoir as the field continued to deplete Once a validated prediction of sand failure had been constructed for the reservoir, the study investigated improvements to the well design that would give both economic production rates and sand-free production for the lifetime of the field. In addition to considering geomechanical properties, the study investigated the geometry of the completion to find the most stable orientations for the wellbore and the perforations. After an economic feasibility study, one of the abandoned wells was sidetracked along the optimally selected trajectory and perforated with oriented guns, isolating identified weak zones. The field has been producing since this remedial work without any sand production, and the missed production has been recovered. As the results, this meets the operator production and recovery objectives for the field.

Sand and fines production is one of the oldest problems in the petroleum industry and one of the toughest to solve. Today, many sand control technologies and methods exist and in certain cases some sand and fines production is manageable, while for others it cannot be tolerated at all. Also, many wells do not produce sand or fines from the onset and may not require a sand control solution until later in their lives. Chemical sand control solutions have been around for many years and have always been attractive due to their ability to be installed without any restrictions to the well bore geometry. However due to the difficulties with placement, and in many cases their association with some degree of reduction in permeability, there have been reservations regarding the use of chemical methods as a standard. This paper presents a unique chemistry that increases the maximum sand/fines free rate without a significant reduction in permeability and discusses the advanced placement techniques essential for a successful application. It includes study of two hundred and fifty wells which have been treated with zeta potential altering chemistry and presents analysis of both failed and successful applications and the lessons learned.

This paper pertains to prediction of elastic rock parameters and sanding problem onset based on petrophysical logs as a novel in-situ method. The paper addresses two main parts. In the first part, petrophysical evaluation of well log data is coupled to the Mohr-Coulomb failure criterion to predict the critical well bore pressure. Mathematical modeling is performed to demonstrate the application of well logs for prediction of sanding problem onset. In the second part, two sets of well log data from fields A and B in the Barents Sea (Norway) are used to show the applicability of the method. It has been shown that the critical well bore pressure for the Tubåen formation in field A is negative indicting the low possibility of sand production while in the field B, the critical well bore pressure is positive for the same formation. The sanding problem in field B has been observed during production and confirms the validity of the method. The different behavior of the two case studies can be linked to the packing of sand grains and cementation due to the burial depth and considerable overburden pressure. The presence of hydrocarbon and water in field B results to the diversity of sonic travel times and the rock elastic parameters compared to the corresponding data of the field A where the formation fluid is only water.

There are two types of sand retention tests generally used in the industry to evaluate the performance of sand control screens for standalone screen applications: pre-pack tests and slurry tests. They represent complete hole collapse and gradual rock failure around the wellbore, respectively. In this paper, we present analytical results as well as Monte Carlo simulations to estimate sand production in slurry type sand retention tests with square mesh screens taking into account the full particle size distribution of the formation sand. We also compare the model results with experimental data and demonstrate that this approach can be used to predict sand production for different sand size distribution/screen size combinations without the need for physical tests. This work augments previously published slurry test models that were limited to wire-wrap screens, and enables comparison of the performance of square mesh screens to wire-wrap screens. The analytical model along with Monte Carlo simulations provide a direct and reliable way to estimate the amount of sand that will be produced for a given sand size distribution and a given screen size. Since the proposed methods are much more quantitative, they represent a significant improvement over current methods that rely on single design points or rules of thumb for screen selection.

Tunu and Tambora gas fields are located in the Mahakam river delta in the province of East Kalimantan, Indonesia. The fields consist of wet gas bearing sand bodies over a height of 13000 ft. Most of the wells are multizone gas producers completed with cemented tubing without primary sand control, and are produced with a bottom-up perforation strategy. The main objective is gas production from the deeper Main Zone layers. The shallower reservoirs prone to sand production were not targeted until recent years. With progressing depletion of deep reservoirs in the Main Zone and bottom up perforation strategy the operator started perforating upper zones. This resulted in an increasing number of interventions or shutting wells in due to sand production. Due to this fact the operator started considering remedial sand consolidation about 5 years ago. The first successful trials using internally catalysed epoxy resin fluid were prepared in late 2008 and results presented at the 2010 SPE International Symposium and Exhibition on Formation Damage Control ( Chaloupka et al. 2010 ). Initially, these consolidation treatments aimed to find a remedial solution for existing wells choked back or shut in due to sand production. These successful trials, however, quickly turned the project into using consolidation essentially as a primary sand control method. First treatments targeted weakly consolidated sands in both Tunu and Tambora fields (5,000 to 8,000 ftTVD) using high temperature internally catalysed epoxy consolidation fluid. The treatments showed encouraging results and confirmed this as a viable option for sand control. In 2010 with growing confidence in the method the operator considered performing sand consolidation in very shallow fully unconsolidated Tunu Shallow zones (2,300 to 5,000 ftTVD) as an alternative to standard single trip multi-zone gravel packs which are conventionally pumped in Tunu Shallow. Five treatments have been performed using a low temperature version of the consolidation fluid with encouraging results. The preliminary performance envelope validated from the treatment is 3 MMscfd of gas per meter perforated or a drawdown of 300 psi. The paper aims to describe the experience from the initial trials to field application including placement and fluid QAQC procedures as well as treatment results. The failures and difficulties that have been encountered are looked at in more details.

Results from sand retention tests (SRT) performed with different screens and test sands can show significant differences in perceived production performance given by the permeability of the retained sand layer as well as sand control behavior. However, this paper presents a new sand retention test set up that exhibits no plugging tendencies for various screen designs when using non-uniform test sands with high content of fines material (U c =7.5, fines = 18%).13 screen designs, 12 metal mesh and one wire wrapped screen, with screen gauges varying from 200 to 275 microns were tested. The results show insignificant differences when it comes to sand control as well as the permeability of the sand layer calculated from the pressure drop across the screen and the sand layer retained by the screen. This work supports critical reviews made by other authors of the various laboratory testing procedures used in the industry and confirms that interpretation of screen performance is often incorrect with these set-ups. The new test set up was developed to enable screen testing under more realistic conditions. Emphasis was placed on low velocities to avoid turbulent, non Darcy effects as well as avoiding the use of fluids containing polymers. High flow rates tend to cause rapid and efficient localization of the sand grains around the sand screen filter openings prior to the establishment of the sand layer. A set up where the total pressure drop is dominated by the turbulent part can readily lead to inaccurate determination of the true permeability and consequently erroneous comparison of screen behavior. With the low approach velocities used in this setup, sand layers of measureable thickness can develop before the pressure rating of the cell is reached. The sand layer permeability is calculated by using Darcy ’ law based on the thickness, flow rate, fluid viscosity and pressure drop. The measured volume of sand produced through the screens in relation to the total volume pumped was used to define their sand control behavior. The flow rate used in this study was 160 ml/min which gives an approach velocity of 0.00053 m/s. Although this is sufficiently low to ensure the absence of non Darcy effects in the resulting sand packs around the screens, it still equates to relatively high rates in the field. For instance, this test rate represents a production rate of 36000 Sm 3 /d through a 2000 m long 6 5/8" screen section which is a normal length on some fields in the North Sea. In the storage cell where the test sand slurry is kept prior to injection into the sand screen test cell, the sand is suspended in brine with a matching density. In this way, a viscous carrier fluid is not required, thus eliminating any possible test artifacts based on undesired polymer effects. The results show that screen plugging with porous test sands is not an issue for any screens given that sensible apertures are chosen that give retention whilst allowing the production of any mobile fines present. The test results confirm that other SRT set-ups with inherently high approach velocities will often misinterpret the pressure response as plugging and thereby rank the various screens incorrectly. Based on these results, and providing that the various screen designs give sand control, the choice of optimum sand screen for a given application should be based more on mechanical properties, cost and contractual issues, other functionality (such as ICD or shroud) rather than "plugging" potential that is erroneously ascribed to different screens in standard SRTs. Screen plugging from other factors during installation and service in the field is, however, possible and should be minimized by good design and operational practice.

Tunu and Tambora gas fields are located in the Mahakam river delta in the province of East Kalimantan, Indonesia. The fields consist of wet gas bearing sand bodies over a height of 13000 ft. The main producing zones are developed by intensive drilling with wells simply completed to allow a bottom up perforation strategy. The main objective is gas production from the deeper Main Zone layers. The shallow reservoirs prone to sand production are not primarily targeted. When sand production after additional perforation is observed, gas production is normally limited to maximum sand free rates or the wells are shut in to avoid damage to surface equipment. Sand consolidation has been used as a sand control method since the 1940’s. However, it had never been attempted in operator’s fields in Indonesia. To author’s knowledge sand consolidation is not commonly used in South East Asia, in general. Unlike widely used conventional sand control methods this alternative method allows production from sand prone reservoirs while maintaining full wellbore access below treated zones. The treatments presented in this paper were to validate sand consolidation as a viable sand control option in operator’s fields in the Mahakam Delta, utilizing new internally catalyzed epoxy consolidation fluid. The treatments were performed with 1.75’’ coil tubing and a packer. To date three Tunu/Tambora wells have been treated. The treated reservoirs have been producing without sand production after treatment. This paper describes candidate selection, job execution and treatment results.