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Challenges and Potentials for Sand and Flow Control and Management in the Sandstone Oil Fields of Kazakhstan: A Literature Review
Soroush, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Roostaei, Morteza (RGL Reservoir Management Inc.) | Hosseini, Seyed Abolhassan (University of Alberta and RGL Reservoir Management Inc.) | Mohammadtabar, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Pourafshary, Peyman (Nazarbayev University) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Ghalambor, Ali (Oil Center Research International) | Fattahpour, Vahidoddin (RGL Reservoir Management Inc.)
Summary Kazakhstan owns one of the largest global oil reserves (approximately 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, payโzone thickness, viscosity, particleโsize distribution (PSD), clay content, porosity, permeability, gas cap, bottomwater, 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, the geological condition, including the existing structures, layers, and formations, were addressed for different reserves. Weakly consolidated heavyโoil reserves in shallow depths (less than 500โm true vertical depth) with oil viscosity of approximately 500 cp and thin pay zones (less than 10โm) 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 compared with the similar cases in North America. The complicated tectonic history necessitates geomechanical models to strategize the sand control, especially in cased and perforated completions. These models are usually avoided in North America because of the lessโproblematic conditions. Further investigation has shown that inflowโcontrol devices (ICDs) could be used to limit the water breakthrough, because water coning is a common problem that begins and intensifies the sanding. This paper provides a review on challenges and potentials for sand control and sand management in heavyโoil 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.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (1.00)
- North America > United States > California (0.67)
- Asia > Kazakhstan > Mangystau Region > Caspian Sea (0.28)
- Overview (1.00)
- Research Report > New Finding (0.92)
- Phanerozoic > Paleozoic > Permian (1.00)
- Phanerozoic > Mesozoic > Triassic (1.00)
- Phanerozoic > Mesozoic > Jurassic (1.00)
- (2 more...)
- Geology > Structural Geology (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- (4 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.92)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Sand Control > Screen selection (1.00)
- (25 more...)
Experiments with Stand-Alone Sand-Screen Specimens for Thermal Projects
Fattahpour, Vahidoddin (RGL Reservoir Management Inc.) | Roostaei, Morteza (RGL Reservoir Management Inc.) | Hosseini, Seyed Abolhassan (University of Alberta) | Soroush, Mohammad (University of Alberta) | Berner, Kelly (RGL Reservoir Management Inc.) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Al-hadhrami, Ahmed (Occidental Petroleum Oman) | Ghalambor, Ali (Oil Center Research International)
Summary Most of the test protocols developed to evaluate sand-screen designs were based on scaled-screen test coupons. There have been discussions regarding the reliability of such tests on scaled test coupons. This paper presents the results of tests on wire-wrapped screen (WWS) and slotted liner (SL) test coupons for typical onshore Canada McMurray formation sand. A unique sand control evaluation apparatus has been designed and built to accommodate all common stand-alone screens that are 3.5 in. in diameter and 12 in. This setup provides the capability to have a radial measurement of pressure across the sandpack and screen for three-phase flow. Certain challenges during testing such as establishing uniform radial flow and measuring the differential pressure are outlined. Produced sand is also measured during the test. The main outputs of the test are to assess the sand control performance and the mode of sanding in different flow directions, flow rates, and flow regimes. It was possible to establish uniform radial flow in both high-and low-permeability sandpacks. However, the establishment of radial flow in sandpacks with very high permeability was challenging. The pressure measurement at different points in the radial direction around the screen indicated a uniform radial flow. Results of the tests on a representative particle size distribution (PSD) from the McMurray Formation on the WWS and SL test coupons with commonly used specifications in the industry (aperture sizes of 0.012, 0.014, and 0.016 in. We also included aperture sizes smaller and larger than the common practice. Similar to previous tests, narrower apertures are proven to be less resistant to plugging than wider slots for both WWS and SL. Accumulation of fines close to the screen causes significant pore plugging when conservative aperture sizes were used for both WWS and SL. In contrast, using the test coupon with a larger aperture size than the industry practice resulted in excessive sanding. The experiments under linear flow seem more conservative because their results show more produced sand and smaller retained permeability in comparison to the testing under radial flow. It also provides insight into the fluid flow, fines migration, clogging, and bridging in the vicinity of sand screens. Introduction Sand production is one of the important phenomena in oil recovery from weakly consolidated and unconsolidated sandstone oil reservoirs. Because of operational and financial constraints such as workover and well cleaning costs, operators tolerate a limited amount of sand production in oil wells.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada > Alberta (0.96)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Van Field (0.93)
- Well Completion > Sand Control > Screen selection (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Full-Scale Physical Modeling of Stand-Alone Screens for Thermal Projects
Fattahpour, Vahidoddin (RGL Reservoir Management Inc.) | Roostaei, Morteza (RGL Reservoir Management Inc.) | Soroush, Mohammad (RGL Reservoir Management Inc., University of Alberta) | Hosseini, Seyed Abolhassan (RGL Reservoir Management Inc., University of Alberta) | Berner, Kelly (RGL Reservoir Management Inc.) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Al-hadhrami, Ahmed (Occidental Petroleum Oman) | Ghalambor, Ali (Oil Center Research International)
Abstract Standalone screens (SAS) have been widely employed as the main sand control solution in thermal projects in Western Canada. Most of the test protocols developed to evaluate screen designs were based on the scaled screen coupons. There have been discussions regarding the reliability of such tests on scaled coupons. This paper presents the results of the tests on full-scale wire-wrapped screen (WWS) and slotted liner coupons for typical McMurray Formation sands. A large-scale sand control evaluation apparatus has been designed and built to accommodate all common SAS with 3 1/2โณ in diameter and 12โณ in height. The set-up provides the capability to have the radial measurement of the pressure across the sand pack and liner, for three-phase flow. We outline certain challenges in conducting full-scale testing such as establishing uniform radial flow and measuring the differential pressure. Produced sand is also measured during the test. The main outputs of the test are to assess the sand control performance and the mode of sanding in different flow direction, flow rates and flow regimes. We were able to establish uniform radial flow in both high and low permeability sand packs. However, the establishment of the radial flow in sand packs with very high permeability was extremely challenging. The pressure measurement in different points in radial direction around the liner indicated a uniform radial flow. Results of the tests on a representative PSD from McMurray Formation on the WWS and slotted liner coupons with commonly used specs in the industry have shown similar sanding and flow performances. We also included aperture sizes smaller and larger than the common practice. Similar to the previous large-scale tests, narrower apertures are proven to be less resistant to plugging than wider slots for both WWS and slotted liner. Accumulation of the fines close to screen causes significant pore plugging, when conservative aperture sizes were used for both WWS and slotted liner. On the other hand, using the coupon with larger aperture size than the industry practice, resulted in excessive sanding. The experiments under linear flow seems more conservative as their results show higher produced sand and lower retained permeability, in comparison to the full scaled testing under radial flow. This work discusses the significance, procedure, challenges and early results of full-scale physical modeling of SAS in thermal operation. It also provides an insight into the fluid flow, fines migration, clogging and bridging in the vicinity of sand screens.
- North America > United States (1.00)
- Asia (0.94)
- North America > Canada > Alberta (0.73)
- Well Completion > Sand Control > Screen selection (1.00)
- Well Completion > Sand Control > Sand/solids control (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Summary Loading up of liquids in wellbore has been recognized as one of the severe problems in gas production for many years. Accurate prediction of the problem is vitally important for taking timely measures to solve the problem. Although previous investigators have suggested several methods to predict the problem, results from these methods often show discrepancies. Also, these methods are not easy to use because of the difficulties with prediction of bottomhole pressure in multiphase flow. An accurate and easy-to-use method is highly desirable. This paper fills the gap. Starting from Turner's analysis for prediction of the minimum gas velocity for liquid removal, the minimum kinetic energy of gas that is required to lift liquid droplets was determined in this study. In order to compare gas kinetic energy with the minimum required kinetic energy, a four-phase (gas, oil, water, and solid particles) flow model was developed for mist flow. Applying the minimum kinetic energy criterion to the four-phase flow model resulted in a closed-form analytical equation for predicting the minimum gas-flow rate. The kinetic energy theory indicates that the controlling conditions for liquid drop removal in gas wells are bottomhole conditions rather than tophole conditions. Our case studies show that Turner's method with 20% adjustment still underestimates the minimum gas velocity for liquid removal, and the newly developed equation is more accurate than Turner's method. The new method is easier to use than other existing methods. This paper provides production engineers with a systematic approach to predicting the minimum gas production rate for the continuous removal of water and oil from gas wells. Engineering charts are provided for two typical tubing sizes and wellhead pressures. Introduction Gas wells usually produce natural gas carrying liquid water and/or condensate in the form of mist. As the gas flow velocity in the well drops owing to the reservoir pressure depletion, the carrying capacity of the gas decreases. When the gas velocity drops to a critical level, liquids begin to accumulate in the well, and the well flow can undergo annular flow regime followed by a slug flow regime. The accumulation of liquids (liquid loading) increases bottomhole pressure that reduces gas-production rate. Low gas-production rate will cause gas velocity to drop further. Eventually, the well will undergo bubbly flow regime and cease producing. Several measures can be taken to solve the liquid-loading problem. Foaming the liquid water can enable the gas to lift water from the well. Using smaller tubing or creating a lower wellhead pressure sometimes can keep mist flow. The well can be unloaded by gas lifting or pumping the liquids out of the well. Heating the wellbore can prevent liquid condensation. Downhole injection of water into an underlying disposal zone is another option. However, liquid loading is not always obvious, and recognizing the liquid-loading problem is not an easy task. A thorough diagnostic analysis of well data needs to be performed. The symptoms to look for include onset of liquid slugs at the surface of the well, increasing difference between the tubing and casing pressures with time, sharp changes in gradient on a flowing pressure survey, and sharp drops in a production decline curve. Turner et al. (1969) were the pioneer investigators who analyzed and predicted the minimum gas flow rate to prevent liquid loading. They presented two mathematical models to describe the liquid-loading problem: the film movement model and entrained drop movement model. On the basis of analyses of field data, they concluded that the film movement model does not represent the controlling liquid-transport mechanism.
Summary Accurate predictions of heat loss and temperature profile in oil- and gas-production pipelines are essential to designing and evaluating pipeline operations. Although some sophisticated computer packages are available for such purposes, their accuracies suffer from numerical treatments and model-building skills of inexperienced users. A simple and accurate analytical heat-transfer model is highly desirable. This paper presents three analytical heat-transfer solutions for predicting heat loss and temperature profiles in pipelines transporting petroleum fluids. The three solutions consist of one steady-state-flow solution and two transient-flow solutions. The two transient-flow solutions are for startup mode and flow-rate-change mode (shutting down is a special mode in which the flow rate changes to zero). An application example is presented to illustrate how the models can be used in insulation design of an offshore pipeline. Introduction Heat transfer across the insulation of pipelines presents a unique problem affecting flow efficiency. Although sophisticated computer packages are available for predicting fluid temperatures, their accuracies suffer from numerical treatments because long pipe segments have to be used to save computing time. This is especially true for transient-fluid-flow analyses in which a very large number of numerical iterations are performed. Ramey (1962) was among the first investigators who studied radial heat transfer across a well casing with no insulation. He derived a mathematical heat-transfer model for an outer medium that is infinitely large. Miller (1980) analyzed heat transfer around a geothermal wellbore without insulation. Winterfeld (1989) and Almehaideb and Pedrosa (1989) considered temperature effect on pressure-transient analyses in well testing. Stone et al. (1989) developed a numerical simulator to couple fluid flow and heat flow in a wellbore and reservoir. More advanced studies on the wellbore heat-transfer problem were conducted by Hasan and Kabir (1994, 2002), Hasan, Kabir, and Wang (1997, 1998), and Kabir et al. (1996). Although multilayers of materials have been considered in these studies, the external temperature gradient in the longitudinal direction has not been systematically taken into account. Traditionally, if the outer temperature changes with length, the pipe must be divided into segments, with assumed constant outer temperature in each segment, and numerical algorithms are required for heat-transfer computation. The accuracy of the computation depends on the number of segments used. Fine segments can be employed to ensure accuracy with computing time sacrificed. Therefore, accurate heat-transfer equations of closed form are highly desirable. The objective of this study was to develop analytical solutions to the heat-transfer problems under various operating conditions. This paper presents three analytical heat-transfer solutions. They are the transient-flow solution for startup mode, steady-state flow solution for normal operation mode, and transient-flow solution for flow-rate-change mode (shutting down is a special mode in which the flow rate changes to zero). An application case is illustrated in which the model-calculated temperature profiles were used for insulation design.
- Asia (0.68)
- North America > United States > Louisiana (0.30)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.32)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract Loading up of liquids in wellbore has been recognized as one of the severe problems in gas production for many years. Accurate prediction of the problem is vitally important for taking timely measures to solve the problem. Although previous investigators have suggested several methods to predict the problem, results from these methods often show discrepancies. Also these methods are not easy to use due to the difficulties with prediction of bottom hole pressure in multiphase flow. An accurate and easy-to-use method is highly desirable. This paper fills the gap. Starting from Turner's analysis for prediction of the minimum gas velocity for liquid removal, the minimum kinetic energy of gas that is required to lift liquid droplets was determined in this study. In order to compare gas kinetic energy with the minimum required kinetic energy, a 4-phase (gas, oil, water, and solid particles) flow model was developed for mist flow. Applying the minimum kinetic energy criterion to the 4-phase flow model resulted in a closed form analytical equation for predicting the minimum gas flow rate. The kinetic energy theory indicates that the controlling conditions for liquid drop removal in gas wells are bottom hole conditions rather than top-hole conditions. Our case studies show that Turner's method with 20%-adjustment still under-estimates the minimum gas velocity for liquid removal, and the newly developed equation is more accurate than Turner's method. The new method is easier to use than other existing methods. This paper provides production engineers with a systematic approach to predicting the minimum gas production rate for the continuous removal of water and oil from gas wells. Engineering charts are provided for two typical tubing sizes and wellhead pressures. Introduction Gas wells usually produce natural gas carrying liquid water and/or condensate in the form of mist. As the gas flow velocity in the well drops owing to the reservoir pressure depletion, the carrying capacity of the gas decreases. When the gas velocity drops to a critical level, liquids begin to accumulate in the well and the well flow can undergo annular flow regime followed by a slug flow regime. The accumulation of liquids (liquid loading) increases bottom hole pressure that reduces gas production rate. Low gas production rate will cause gas velocity to drop further. Eventually the well will undergo bubbly flow regime and cease producing. Several measures can be taken to solve the liquid loading problem. Foaming the liquid water can enable the gas to lift water from the well. Using smaller tubing or creating a lower wellhead pressure sometimes can keep mist flow. The well can be unloaded by gas-lifting or pumping the liquids out of the well. Heating the wellbore can prevent liquid condensation. Down-hole injection of water into an underlying disposal zone is another option. However, liquid loading is not always obvious and recognizing the liquid loading problem is not an easy task. A thorough diagnostic analysis of well data needs to be performed. The symptoms to look for include onset of liquid slugs at the surface of well, increasing difference between the tubing and casing pressures with time, sharp changes in gradient on a flowing pressure survey, and sharp drops in a production decline curve.
Abstract Accurate predictions of heat loss and temperature profile in thermal injection lines and wellbores are essential to designing and evaluating thermal operations. Although some sophisticated computer packages are available for such purpose, their accuracies suffer from numerical treatments and model-building skills of inexperienced users. A simple-and-accurate analytical heat transfer model is highly desirable. This paper presents three analytical heat transfer solutions for predicting heat loss and temperature profiles in thermal-insulated flow conduits. The three solutions consist of one steady state flow solution and two transient flow solutions. The two transient flow solutions are for start-up mode and flow rate change mode (shutting-down is a special mode where the flow rate changes to zero). Capability of the analytical model is investigated using a data set that is representative to a typical case of liquid flow in a small-diameter thermal pipeline. An application example is illustrated where the model-calculated temperature profile is used to identify the possible interval of asphaltene deposition in an oil well. The mathematical heat transfer model can also be used for predicting temperature distribution in offshore pipelines. Introduction Heat transfer across the insulation of pipelines and wellbores presents a unique problem affecting flow efficiency. Although sophisticated computer packages are available for predicting the fluid temperatures, their accuracies suffer from numerical treatments because long-pipe segments have to be used to save computing time. This is especially true for transient fluid-flow analyses where a very large number of numerical iterations are performed. Ramey was among the first investigators who studied radial heat transfer across a well casing with no insulation. He derived a mathematical heat transfer model for an outer medium that is infinitely large. Miller analyzed heat transfer around a geothermal wellbore without insulation. Winterfeld and Almehaideb considered temperature effect on pressure transient analyses in well testing. Stone et al. developed a numerical simulator to couple fluid flow and heat flow in a wellbore and reservoir. More advanced studies on the wellbore heat transfer problem were conducted by Hasan and Kabir. Although multi-layers of materials have been considered in these studies, the temperature gradient in the longitudinal direction has not been taken into account. Traditionally, if the outer temperature changes with length, the pipe must be divided into segments with assumed constant outer-temperature in each segment, and numerical algorithms are required for heat transfer computation. The accuracy of the computation depends on the number of segments used. Fine segments can be employed to ensure accuracy with computing time sacrificed. Therefore, accurate heat transfer equations of closed-form are highly desirable. The objective of this study was to develop analytical solutions to the heat transfer problem under various operating conditions. This paper presents three analytical heat transfer solutions. They are transient flow solution for start-up mode, steady flow solution for normal operation mode, and transient flow solution for flow rate change mode (shutting-down is a special mode where the flow rate changes to zero). Sensitivity analyses are run to investigate the capability of the analytical model using a data set that is representative to a typical case of liquid flow in a small-diameter thermal pipeline. An application case is illustrated where the model-calculated temperature profile with the model was utilized to identify the possible interval of paraffin deposition in an oil wellbore.
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract Underbalanced drilling (UBD) has gained strong momentum in recent years because of a number of advantages of the technology including reduced formation damage and minimized lost circulation. Due to the complex nature of water, oil, gas and solid multiphase flow in the UBD systems, numerous runs of sophisticated computer programs are required to draw the boundary of the safe gas-liquid rate envelope. It is highly desirable to have a simple and reliable procedure to perform optimum UBD designs. This paper describes an innovative procedure to delineate the boundary of the safe gas-liquid rate envelope for UBD flow rates. In developing the safe gas-liquid rate envelope, formation fluid pressure limits the upper bound of the flowing bottom hole pressure and wellbore collapse pressure serves the lower bound of the circulation-break bottom hole pressure. The envelope is closed with boundaries determined by fluid's cutting carrying capacity and wellbore washout criteria. Detailed procedure for the development of the safe gas-liquid rate envelope using a spreadsheet program is described in the paper. A successful field UBD case is reviewed and compared with the safe gas-liquid rate envelope. This work provides drilling engineers and drilling supervisors an easy-to-use approach to designing and modifying gas and liquid injection rates in UBD. The safe gas-liquid rate envelope can also be used for evaluating feasibility of UBD under given geological conditions. Introduction The drilling operations where the drilling fluid pressures in the borehole are intentionally maintained to be less than the pore pressure in the formation rock in the open-hole section is called Underbalanced drilling (UBD). The low borehole pressures are achieved by using lightened drilling fluids. The light fluids used in UBD are usually air, gas, foam, and aerated water. However, un-aerated oil, water, even weighted mud can be used for UBD in areas where formation pore pressure gradients are higher than hydrostatic pressure gradient of water. The advantages of UBD include increased penetration rate, minimized lost circulation, prolonged bit life, minimized differential sticking, improved formation evaluation, reduced formation damage (reduced stimulation requirements), earlier oil production, larger wellbore available to production in offshore, and environmental benefits. The disadvantages of UBD include personnel and equipment safety issues, handling of produced formation fluids, and wellbore damages (washout, collapse, and cuttings accumulation in the borehole). Good designs are the key to the successful UBD operations. Sever wellbore damages and failures can result from poor UBD designs and/or deviation of the actual drilling programs from the original designs. The combination of mud flow rate and gas injection rate plays a very important role in preventing failure of the UBD. If the combination is chosen such that it gives too high bottom hole pressures, the degree of underbalance is reduced and the benefit of the UBD will be marginal. On the other hand, if the combination is chosen such that it gives too low bottom hole pressures, wellbore damage problem will fail the UBD operation. Currently computer simulators have been used in drilling industry to design liquid and gas injection rate combinations for UBD. Both steady state and transient simulators are available. But the procedure is tedious and not transparent. It is difficult to make an optimum UBD design that balances all the aspects. A graphical method with methodology transparency is highly desirable for drilling engineers who are in charge of UBD designs and UBD field supervisions.
- Asia (0.93)
- North America > United States > Texas (0.28)
Abstract Sachdeva's multiphase choke flow model has capabilities of predicting critical-subcritical boundary and liquid and gas flow rates for given upstream and downstream pressures. Although this model was shown to be accurate by Sachdeva et al. in their original paper using laboratory and field data, inaccuracy of the model has been found in other field applications. It is highly desirable for production engineers to find the applicability of this model when it is applied to gas condensate wells. In this study, the accuracy of the Sachdeva's choke model was evaluated using data from oil and gas condensate wells in Southwest Louisiana. Comparisons of the results from the model and field measurements indicate that Sachdeva's choke model generally under-estimates gas and condensate flow rates. Based on measurements from 239 gas condensate wells it was found that the model under-estimates gas rate and liquid rate by as much as 40% and 60%, respectively. The model also failed to calculate mass flow rates for 48 condensate wells where relatively low-pressure differentials at chokes and high-flow rates were observed. The investigation further went on to improve the performance of Sachdeva's choke model. It was found that the error of the model could be minimized using different values of choke discharge coefficient (CD). For gas condensate wells, the error in gas flow rate calculations can be minimized using CD = 1.073. However, the error in liquid flow rate calculations for condensate wells is minimum when CD = 1.532. Introduction Computer technology has been widely used for simulation of petroleum production network today. The production network consists of reservoirs, wellbore equipment, and surface equipment including chokes, flow lines, production manifolds, and distilation facilities such as separators. The production network simulation has gained strong momentum due to fast advances in computing technology in the past five years. Wellhead chokes are special equipment used in energy industry to control fluid production rates from wells, to maintain stable pressure downstream from the choke, and to provide the necessary backpressure to a reservoir to avoid formation damage from excessive drawdown. Because oil and gas production rates are extremely sensitive to choke size, accurate modelling of choke performance is vitally important for petroleum engineers in oil production simulation.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)