Flowing Bottomhole Pressure Research Articles

History-matching and forecasting tight/shale gas condensate wells using combined analytical, semi-analytical, and empirical methods

The primary focus of the majority of current, and foreseeable, natural gas drilling within North America is low-permeability liquid-rich gas and gas condensate reservoirs, where the liquid fraction is now a major source of revenue. Development of these liquid-rich resources is aided by the use of multi-fractured horizontal wells (MFHWs), and is at an early stage; further research is required to appropriately manage the resource for optimal hydrocarbon recovery.The appropriate forecasting methodologies to apply to these tight liquid-rich plays are a focus of current research. While numerical simulation is the most rigorous forecasting methodology, practitioners have turned to simple analytical and empirical methods because of their ease-of-use and requirement of less data. However, these analytical and empirical approaches have limitations that limit their applicability for unconventional resevoirs with complex reservoir, hydraulic fracture and fluid properties.In this study, the workflow of Clarkson (2013b) is applied to address the limitations of existing empirical and analytical methods for forecasting MFHWs producing from liquid-rich tight gas/shale. The workflow calls for constraint of analytical models by linking inputs to rate-transient analysis-derived reservoir and hydraulic fracture properties, and constraining empirical model forecasts to be consistent with analytical model forecasts. In order to address the range in reservoir/fracture properties observed in shales, a suite of analytical models is proposed. Similarly, a suite of empirical methods is used, and the models yielding the most accurate matches to the analytical models are selected for forecasting. Lastly, in order to bridge the gap between analytical and empirical methods, the semi-analytical method introduced by Clarkson and Qanbari (2015), which has as its basis the contacted gas-in-place calculations of Agarwal (2010), is also used for forecasting.An important contribution of this work is the demonstration of the applicability of the analytical and semi-analytical models used in this work for tight gas/shale gas condensate MFHWs exhibiting multi-phase flow in the reservoir. As demonstrated in this study using simulation cases, constant condensate gas ratios can occur for tight/shale gas condensate wells exhibiting transient linear flow and flowing at near constant flowing bottomhole pressure, even for relatively rich gas cases, rendering the single-phase forecasting methods useful for forecasting gas and condensate phases. The accuracy of these methods is tested using simulated cases, and practicality of the workflow demonstrated using an actual field example of a liquid-rich shale MFHW.This study will be of interest to those petroleum engineers who are faced with forecasting a large number of liquid-rich shale wells, and desire methods that can be simply applied to constrain forecasts and improve accuracy.

Sand production assessment considering the reservoir geomechanics and water breakthrough

Sand production assessment is essential from the early stages of field development planning for completion design and later for the production optimisation. Unconsolidated and weakly consolidated sandstones are prone to fail at a low flowing bottomhole pressure during hydrocarbon production. To predict the critical flowing bottomhole pressure or a safe drawdown, a geomechanical model that integrates in situ stresses, rock mechanical properties, the well trajectory, reservoir pressure, the production plan and the depletion trend is required. For a given stress field, well trajectory and production plan, the rock strength index is a key parameter that has significant impacts on the sanding risk. This paper presents the results of a study investigating the potential of sand production from primary and secondary target reservoir rocks in a petroleum field in offshore Vietnam. A poroelastic analytical approach was used to investigate if sands will be produced from the open holes or perforations. The criterion of sanding was formulated to be the effective maximum principal stress to be greater than the effective rock strength. Observations of sanding or no sanding during drill stem tests (DSTs) were used to calibrate the sanding model to be used for sanding predictions of future production wells. The effects of reservoir pressure depletion on sanding risks were investigated using the stress arching theory. Since the water production from target reservoirs was observed in the nearby fields, the analysis was performed to investigate the effects of water production on rock weakening that may cause higher risks of sanding. The results showed low risks of sanding for majority of the reservoirs, with drawdowns as high as 3,000 psi at the original reservoir pressure. The drawdown was, however, required to reduce to 500 psi to produce sand-free after depleting the reservoir by more than 90% of its original pressure. The results of this study led to the decision of completing the wells without using sand control equipment and to avoid sanding by controlling drawdown for the life of the well.

Production data analysis of tight gas condensate reservoirs

The current focus on liquids-rich shale (LRS) plays in North America underscores the need to develop reservoir engineering methods to analyze such reservoirs. Commercialization of LRS plays is now possible due to new technology, such as multi-fractured horizontal wells (MFHW). Efficient production from such reservoirs necessitates understanding of flow mechanisms, reservoir properties and the controlling rock and fluid parameters. Production-decline analysis is an important technique for analysis of production data and obtaining estimates of recoverable reserves. Nevertheless, these techniques, developed for conventional reservoirs, are not appropriate for ultra-low permeability reservoirs. There are substantial differences in reservoir performance characteristics between conventional and ultra-low permeability reservoirs. LRS reservoirs produce much leaner wellstreams compared to conventional reservoirs due to very low permeabilities that result in very large drawdowns. Methods for analysis of two-phase flow in conventional reservoirs, with underlying simplifying assumptions, are no longer applicable.This paper discusses production data analysis of constant flowing bottomhole pressure (FBHP) wells producing from LRS (gas condensate) reservoirs. A theoretical basis is developed for a gas condensate reservoir during the transient matrix linear flow (drawdown) period. The governing flow equation is linearized using appropriately defined two-phase pseudopressure and pseudotime functions so that the solutions for liquids can be applied. The derived backward model is employed to compute the linear flow parameter, xf√k.Simulation results show that the liquid yield will be approximately constant for LRS wells during the transient linear flow, from the early days of initial testing, if FBHP is almost constant. An analytical formulation is used to prove this finding for 1D transient linear flow of LRS wells.The proposed production data analysis (PDA) method is illustrated using simulated production data for different fluid models and relative permeability curves. Fine-grid compositional and black oil numerical models are used for this purpose.

Gas Lift Optimization of an Oil Field in Malaysia

Gas lift is an artificial lift method which is commonly used in offshore operation with sufficient gas sources as it consumes minimum space on the platform. Gas lift operates by injecting a high pressure gas down through the tubing casing annulus of a well and the injected gas enters the tubing through a gas lift valve installed on the tubing. Gas lift increases production by two means, density reduction of oil column inside the tubing so that the flowing bottom-hole pressure which is affected by the hydrostatic pressure of the fluid column is reduced and by providing external energy to the oil as the gas expends.Reducing the bottom-hole pressure will improve the drawdown of the well. A production well is modelled by using a production modelling program, Integrated Production Modeling (IPM) Prosper to analyze the production performance at various conditions. A base case model is developed from the production data of an actual oil field to simulate the performance of the actual well without gas lift system. Later, the gas lift is added to the model and the performance was compared with the base case model. The gas parameter was also studied to determine the optimum injection gas condition for maximum oil production. The gas injected at 1490m can be achieved by injecting the gas with 1200 psi, l300 psi or 1400 psi. However, the optimum gas injection pressure was determined to be at 1400 psi as the design shows that the required unloading stage is the least. The optimum gas injection rate was determined at 5 MMscf/d with the estimated net revenue is the highest. For injection gas gravity, the lighter gas was determined to be the optimum selection since it gives significant reduction of FBHP (Flowing Bottom Hole Pressure) with less hydrostatic pressure inside the tubing column.

On the analysis of production data: Practical approaches for hydraulically fractured wells in unconventional reservoirs

Abstract This work presents new solutions to modeling the production performance of hydraulically fractured wells in unconventional reservoirs, where intensive hydraulic fracturing creates a stimulated reservoir volume (SRV) with an induced permeability field within. We found previously that the permeability field induced in the SRV (single porosity) can be effectively represented by an exponential or linear dependence of permeability on the distance measured from the main hydraulic fracture plane. However, many researchers consider dual porosity as a necessary ingredient in modeling unconventional reservoirs. In this work, we extend the induced permeability field model to the dual porosity idealization, considering transient fluid transfer from matrix to natural fractures and distance-dependent properties of the medium of secondary porosity (affected by the intensive stimulation). We show that the combined effect of creating a main fracture and altering the properties of the medium of secondary porosity leads to a production behavior that can be characterized and understood provided that effects related to skin and varying flowing bottomhole pressure are correctly accounted for. In addition to the standard diagnostic tools for decline-curve or rate-transient analysis, we use the ratio between the production time and material balance time, a dimensionless group that enables identifying the characteristic signatures of flow regimes. We provide practical criteria to identify various scenarios affecting the data during the pre-linear and pre-bilinear flow regimes in the reservoir (short times). Then we show that transient, late transient and boundary dominated flow periods can also be diagnosed using the dimensionless group, providing a useful addition to existing procedures involving conventional plots. In connection to the new model, this work also discusses a novel approach to handle non-constant bottomhole pressure, the cause of significant distortion in production data at early times. In particular, we consider the effect of a bottomhole pressure exponentially approaching a stabilized value. We show that the deviation from the idealized constant bottomhole pressure case depends on the flow regime in the reservoir, fluid and reservoir properties, skin factor, and the mean lifetime (the time when 63% of the total change has happened) of the decaying part of the flowing pressure. The results reveal that half-, three-fourths-, and unit-slope straight lines (on log–log plot of production rate versus time) develop at short times during the increasing trend of production rate. These new flow regimes enable to gain useful information about the SRV from the early stage of the production history – if the quality of data allows such a detailed analysis. We present a field example involving multi-fractured horizontal wells producing from a shale-gas reservoir, to illustrate, in a practical manner, how to apply the new approach when interpreting production history of wells in unconventional reservoirs.

Coupled flow-geomechanical performance assessment of CO2 storage sites using the Ensemble Kalman Filter

Abstract A methodology for coupled flow-geomechanical CO2 storage site performance assessment using the ensemble Kalman filter (EnKF) is developed. The methodology is applied to the In Salah case study dataset in order to validate the developed technique. The EnKF approach is used to estimate the parameters controlling the performance of the CO2 storage site by assimilating data from multiple sources. The controlling parameters in this study are fault/fracture transmissibility and anisotropic permeability at the injection wells; and the data sources are the injection wells’ flowing bottom-hole pressure (FBHP) and Interferometric Synthetic Aperture Radar (InSAR) surface deformation. The methodology is shown to be effective in updating the parameters controlling the performance of the CO2 storage site.

Controlling Bottom Hole Flowing Pressure Within a Specific Range for Efficient Coalbed Methane Drainage

The stress state of coal surrounding a coalbed methane (CBM) production well is affected by the bottom hole flowing pressure (BHFP). The permeability of coal shows a marked change under compression. The BHFP must be restricted to a specific range to favor higher permeability in the surrounding coal and thus higher productivity of the well. A new method to determine this specific range is proposed in this paper. Coal has a rather low tensile strength, which induces tensile failure and rock disintegration. The deformation of coal samples under compression has four main stages: compaction, elastic deformation, strain hardening, and strain softening. Permeability is optimal when the coal samples are in the strain softening stage. The three critical values of BHFP, namely, p wmin, p wmid, and p wupper, which correspond to the occurrence of tensile failure, the start of strain softening, and the beginning of plastic deformation, respectively, are derived from theoretical principles. The permeability of coal is in an optimal state when the BHFP is between p wmin and p wmid. The BHFP should be confined to this specific range for the efficient drainage of CBM wells. This method was applied to field operations in three wells in the Hancheng CBM field in China. A comprehensive analysis of drainage data and of the BHFP indicates that the new method is effective and offers significant improvement to current practices.

Reservoir-Fluid Characterization From Tests on Tight Formations

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164887, ’Reservoir-Fluid Characterization From Tests on Tight Formations,’ by Brian Moffatt, Michael Fawcett, Jaimar Maurera, and Anna Bruzco, Petrophase, prepared for the 2013 European Association of Geoscientists and Engineers Annual Conference and Exhibition incorporating SPE Europec, London, 10-13 June. The paper has not been peer reviewed. Drillstem testing of low-permeability reservoirs is challenging because high-pressure drawdown around the wellbore lowers fluids below saturation pressure and creates two-phase flow into the wellbore. The fluids produced at surface no longer represent the original reservoir fluid. This paper shows the benefits of a careful methodology of data selection and equation-of-state (EOS) modeling to validate data used to characterize the reservoir fluid. Introduction There are significant technical difficulties in capturing representative fluid samples from tight formations. Attempts to flow to surface from tight formations induce a fall in pressure around the well-bore that may take the reservoir oil or gas below its saturation pressure. Two-phase flow in the wellbore can cause significant errors for sampling downhole, although surface sampling can be less prone to error. However, because the gas within the formation is more mobile than liquid, the surface gas/oil ratios (GORs) are higher than those of the native fluid. This can lead to erroneous assumptions about the reservoir fluid if the separator samples are recombined to the prevailing GOR without reference to what is happening in the reservoir. Two case studies are presented that resolve apparently conflicting data and use a wider range of well-test data than single data points to define reservoir fluids. Neither study had the benefit of downhole pressure/depth gradients to corroborate reservoir-fluid properties. Characteristic Test Results for Tight-Formation Drillstem Tests (DSTs) DSTs performed where the flowing bottomhole pressure (FBHP) stays above saturation pressures are ideal for surface sampling or for taking bottomhole flowing samples. However, the low deliverability of tight-formation wells often makes it difficult to establish stable flowing conditions. The FBHP, flowing well-head pressure, and separator conditions may all be unstable, causing difficulties in establishing the correct GOR even when the total wellbore composition is constant. A further complication can arise if the gas rates are too low to lift liquids to the surface. GORs for bottomhole samples (BHSs) are measured in the laboratory by flashing the sample to specified conditions. The same wellstream composition sampled at the surface will normally have a lower GOR because separator conditions favor an increase in stable liquid volume. Surface and bottomhole GORs will match only under identical flashing conditions. Typical GOR characteristics for BHSs and surface samples for a tight formation containing oil are shown in Fig. 1.

Inflow-Control Device, Inflow-Control Valves Aid Kuwait's First Smart Multilateral Well

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 159261, ’Novel Design and Implementation of Kuwait's First Smart Multilateral Well With Inflow-Control Device and Inflow-Control Valve for Life-Cycle Reservoir Management in High-Mobility Reservoir, West Kuwait,’ by Om Prakash Das, Khalaf Al-Enezi, Muhammad Aslam, Taher El-Gezeeri, and Khalid Ziyab, SPE, Kuwait Oil Company; and Steven R. Fipke and Steven Ewens, Halliburton, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed. Kuwait’s first smart Level-4 multilateral well was completed in the Burgan reservoir by combining a Level-4 junction with stacked dual-lateral completion with a customized viscosity-independent inflow-control device (ICD), two customized inflow-control valves (ICVs), downhole gauges, a wide-operating-range electrical submersible pump (ESP), suitable wellheads, a tree, and integrated surface panels for real-time data monitoring. The smart multilateral well has assisted in addressing premature water breakthrough, has enhanced water-free oil production, and has facilitated uniform depletion, which results in improved hydrocarbon recovery. Introduction The Minagish field in west Kuwait (Fig. 1) is a north/south-trending anticline with hydrocarbon contained in six major reservoirs (sandstone and carbonate) ranging in age from Early Jurassic to Late Cretaceous. The Burgan sandstone reservoir lies at the crest of the Minagish field. The lower section of the Burgan sandstone reservoir consists of a braided river system with stacked-channel sand bodies that have very high horizontal and vertical permeability (on the order of a few darcies) and are associated with an underlying active aquifer. The combination of high oil viscosity, oil-wet reservoir characteristics, and very high water mobility associated with very high permeability and the presence of fault networks connected to the aquifer accelerates water movement inside the reservoir and results in premature water breakthrough in existing vertical and horizontal wells, despite maintaining highest standoff from the oil/water contact. Smart-Multilateral-Well Architecture and Design The smart-multilateral-well design was customized for ICD completion at the sandface for both the main-bore and upper-lateral intelligent completion including two ICVs, downhole gauges, feed-through packers, and a Level-4 cemented junction to provide fullbore access to the main bore and upper lateral. A schematic of the smart multilateral well is shown in Fig. 2. ICD Selection and Design The following objectives were considered for completion of the horizontal open-hole section of the main bore and upper lateral of the smart multilateral wells: Facilitate uniform inflow across the entire horizontal production section of both the main bore and upper lateral. Control water production from relatively high-permeability layers upon water breakthrough. Allow automatic adjustment to compensate for changes in well-inflow profile over the production life of wells. Provide uniform sweep efficiency across sandface. Minimize annular flow. Minimize pressure drop through ICD housing to improve flowing bottomhole pressure (FBHP) in main bore and upper lateral. Minimize bypassed-oil regions, and maximize oil recovery. Maximize production life of wells.

A Calculation Method for Bottom Hole Flowing Pressure Based on Radial Basis Function

The traditional method using manometers to measure bottom hole flowing pressure (BHFP) is limited by workload and working condition. Meanwhile, the method of forecasting BHFP based on traditional multiphase conduit flow model requires large amount of basic data and the process of calculation is very complicated. Therefore, both of the above methods have their own limitations. This paper has established tripling feed-forward neural network of multiple input but single output by using RBF neural network method in which BHFP serves as output value and the factors influencing the BHFP serve as stimulated input value. After trained by using known samples, the tripling feed-forward neural network has the adequate capacity to be learned and spread. The measured data of QH oilfield and the comparison of data calculated by neural network technique with that calculated by BP method have demonstrated that neural network technique has the characteristics of fast convergence speed and higher accuracy rate in forecasting BHFP and can be applied to these oilfields whose BHFP cannot be directly measured or calculated.

Offshore ESP-Selection Criteria: An Industry Study

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146652, ’Offshore ESP-Selection Criteria: An Industry Study,’ by Michael C. Romer, SPE, Mark E. Johnson, SPE, Pat C. Underwood, SPE, and Amanda L. Albers, SPE, ExxonMobil, and Russ M. Bacon, R.M. Bacon Engineering, prepared for the 2012 SPE Deepwater Drilling and Completions Conference, Galveston, Texas, 20-21 June. The paper has not been peer reviewed. Most offshore wells that require artificial lift are gas lifted because gas typically is readily available and, compared with other lift systems, gas lifting is relatively inexpensive and low maintenance. However, electrical submersible pumps (ESPs) can increase oil production and reserves recovery efficiently and economically under the appropriate operating conditions. ESPs can lower the abandonment pressure and, in the long term, possibly reduce the total number of wells required to deplete an asset. Because few ESPs are installed in offshore wells, ESP-screening “rules of thumb” were formed as a simple guide to prioritize offshore ESP candidates. Introduction Pumps typically achieve higher drawdowns than gas lift under appropriate operating conditions. Early in the life of the pump, greater production is achieved with its higher drawdowns. Note that increased production over the long term must be supported by good reservoir management and voidage-replacement practices. Lowering the flowing bottomhole pressure can improve a well’s access to reserves in stratified reservoirs. Pumps also reduce the burden on the gas-compression system and enable selling gas or reallocating it to other gas lift wells. ESPs have a small topside footprint, do not impair subsurface-safety-valve operation, can achieve high production rates, and can aid fluid processing on production facilities because high-pressure power fluid or gas is not required. However, it can be difficult to determine the best ESP candidates when faced with numerous opportunities, limited resources for reserves studies or artificial-lift analyses, and finite installation capital. ESPs can help maximize an asset’s profitability, and screening criteria can streamline the candidate-selection process. These screening criteria were developed for dry-tree offshore applications. The high complexity, cost, and risk involved with subsea ESP installations and workovers typically have limited subsea pumping to seafloor technologies such as subsea separation, multiphase pumps, cartridge ESPs, and caisson ESPs. This trend may change with continued progress in alternative ESP-deployment/-retrieval technologies and/or run-life and reliability improvements.

Wireless Wellbore - The Way Ahead

Technology Update The trend of increasing wellbore complexity for extended reservoir contact and greater reservoir heterogeneity demands improved monitoring and control solutions. Traditionally, the only option has been the deployment of a cabled system, but this limits the application of intelligent well technology to new installations or workovers. In any case, cabled systems are not always possible in new installations, especially where the completion is discontinuous, and slimhole or monobore completions may not allow cables to be deployed along the tubing string. Wireless technology is proving to be a more flexible alternative to addressing the issues of permanent downhole monitoring. Tendeka’s wireless gauge, an interventionless completion technology that has been successfully deployed in the North Sea, allows real-time flowing bottomhole pressure (FBHP) to be efficiently transmitted to the surface, an attractive option for wells, in which the cabled gauge system has failed or was not initially installed. Originally designed to 3.5 in., the company has recently produced a 2.25 in. version. Benefits of Wireless Technology The system transmits data from the lower completion to the surface via pressure pulses. The tool design allows the well’s production to be partially choked for a short time to create a pressure pulse, which is detectable on the surface pressure gauge. The well’s energy is used to transmit data to surface, thereby reducing power consumption, and the system requires no additional surface installation or pickup because an existing tubing head pressure gauge can be used to detect the pulse train. For most operators, the system can be deployed by a single intervention, allowing highly accurate data to be sourced almost instantaneously for a fraction of the cost of a recompletion. Compared with a memory gauge system, it allows data to be collected in real time and provides a continuous confirmation of operation. The gauge can be set in blank pipe, giving optimal freedom for installation depth, and it can be installed as close to the producing interval as required. A benefit of using pressure pulse transmission is the ease of installation. No retrofitting of topside equipment is required, and many of the technical and contractual issues are avoided when introducing a new monitoring system. Successful Deployment A major operator in the North Sea retrofitted the 3.5 in. wireless pressure and temperature gauge at 2200 m in a low-pressure (32 bar) gas well offshore Norway. The existing wellhead pressure sensor was used to capture the wireless signal and extract the data, therefore, no extra infrastructure was required. The application was especially challenging because the well was a marginal producer and the wellhead pressure had large background pressure variations, because of limited well deliverability. Despite these conditions, pressure pulse transmission proved effective. Even if the well starts to significantly deplete while the wireless downhole gauge is installed, the gauge itself will modify its pressure pulsing method to ensure that a detectable pulse train is transmitted to surface.

Assessment of carbon dioxide plume behaviour within the storage reservoir and the lower caprock around the KB-502 injection well at In Salah

Surface uplift has been detected over all three of the In Salah CO2 injection wells with corresponding subsidence also observed over the gas production area. The distinctive two-lobed uplift pattern over KB-502 has attracted much research interest, as it suggests the tensile opening of a structural discontinuity at depth. The latest reservoir simulation effort at Imperial College involved the implementation of a non-sealing fault (zone) with dynamic transmissibility in the revised reservoir/overburden model and adopted a holistic approach to matching of the estimated flowing bottomhole pressure (FBHP) at KB-502. Based upon the current knowledge of the Krechba stress field and time-elapse InSAR surface uplift images, tensile opening of a pre-existing fault (zone) aligned with the maximum horizontal stress direction and its subsequent growth was analysed with reference to CO2 injection FBHP at KB-502. The history matching results, in terms of the dynamic behaviour of the fault (zone) transmissibility, are found to be consistent with the stress analysis and the field observations.A new interpretation is proposed for the two-lobed surface uplift pattern observed over KB-502. It is postulated that, prior to March 2006 when the injection pressure peaked, the two-lobed surface response was caused primarily by CO2 injection-induced tensile opening of a non-sealing fault zone and its subsequent confined growth (lateral propagation and widening) within the C10 formation. The increasingly pronounced surface uplift pattern observed after March 2006 (against the backdrop of a steady decline in the FBHP), is predominantly a result of localised CO2 migration into and pressurisation of a fracture (or fault damage) zone in the lower caprock by elevated injection pressure, at the top of the tight sandstone formation (C10.3), which is overlying the main storage reservoir (C10.2).

Quantifying reservoir connectivity, in-place volumes, and drainage-area pressures during primary depletion

This study presents an analytical formulation for multiple wells when production interference sets in amongst the wells, including the outer boundaries. This analytical solution estimates the connected pore-volume associated with each well, leading to average-reservoir pressure, and identifies the absence or existence of reservoir continuity. Only flowing bottomhole pressure (BHP) and rate data are needed for the analysis; the knowledge of reservoir geometry or shape factor and average-reservoir pressure is not required.Streamline simulations have aided generation of synthetic cases involving different heterogeneity settings. The new analytical model corroborates the results of those flow simulations. Synthetic examples validate the proposed approach, whereas a field example verifies the notion presented in this study.

Rate-Decline Analysis for Fracture-Dominated Shale Reservoirs

Summary Traditional decline methods such as Arps’ rate/time relations and their variations do not work for wells producing from supertight or shale reservoirs in which fracture flow is dominant. Most of the production data from these wells exhibit fracture-dominated flow regimes and rarely reach late-time flow regimes, even over several years of production. Without the presence of pseudoradial and boundary-dominated flows (BDFs), neither matrix permeability nor drainage area can be established. This indicates that matrix contribution is negligible compared with fracture contribution, and the expected ultimate recovery (EUR) cannot be based on a traditional concept of drainage area. An alternative approach is proposed to estimate EUR from wells in which fracture flow is dominant and matrix contribution is negligible. To support these fracture flows, the connected fracture density of the fractured area must increase over time. This increase is possible because of local stress changes under fracture depletion. Pressure depletion within fracture networks would reactivate the existing faults or fractures, which may breach the hydraulic integrity of the shale that seals these features. If these faults or fractures are reactivated, their permeabilities will increase, facilitating enhanced fluid migration. For fracture flows at a constant flowing bottomhole pressure, a log-log plot of rate over cumulative production vs. time will yield a straight line with a unity slope regardless of fracture types. In practice, a slope of greater than unity is normally observed because of actual field operations, data approximation, and flow-regime changes. A rate/ time or cumulative production/time relationship can be established on the basis of the intercept and slope values of this log-log plot and initial gas rate. Field examples from several supertight and shale gas plays for both dry and high-liquid gas production, and for oil production were used to test the new model. All display the predicted straightline trend, with its slope and intercept related to reservoir types. In other words, a certain fractured flow regime or a combination of flow types that dominate a given area or play because of its reservoir-rock characteristics and/or fracture-stimulation practices all produce a narrow range of intercepts and slopes. An individualwell performance or EUR can be derived that is based on this range if the best 3-month average or the initial production rate of the well is already known or estimated. The results show that this alternative approach is easier to use, gives a reliable EUR, and can be used to replace the traditional decline methods for unconventional reservoirs. The new approach is also able to provide statistical methods to analyze production forecasts of resource plays and to establish a range of results of these forecasts, including probability distributions of reserves in terms of P90 (lower side) to P10 (higher side).

Best Practices in Testing and Analyzing Multilayer Reservoirs

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 132596, ’Best Practices in Testing and Analyzing Multilayer Reservoirs,’ by Yan Pan, SPE, Chevron Energy Technology Company, and Michael Sullivan and David Belanger, SPE, Tengizchevroil, prepared for the 2010 SPE Western Regional Meeting, Anaheim, California, 27-29 May. The paper has not been peer reviewed. Layered formations are the norm rather than the exception among oil and gas reservoirs. Knowing individual-layer properties is important for development strategies, especially for secondary recovery. A set of best practices was established in the design, execution, and analysis of multilayer pressure-transient tests in the Tengiz oil field in western Kazakhstan. Use of multilayer testing and analysis techniques provided a lower level of uncertainty in layered-reservoir characterization than can be obtained with a simpler commingled-pressure-transient test alone. Introduction Formations in the platform area of Tengiz consist of multiple zones with different reservoir pressures. Therefore, crossflow often occurs during shut-in periods. In some cases, the effect from different layer pressures and skin distributions could result in 100% difference in individual-layer permeability estimations. To reduce uncertainty, the selective-inflow-performance (SIP) production-logging technique is used to measure the bottomhole pressures and flow contributions of individual layers during a commingled-pressure-transient test. Pulsed-neutron-capture (PNC) logs are used to gain information about stimulation effectiveness (skin) in each zone. Then, a robust step-by-step analysis method that uses all data and information is applied to obtain individual-layer properties. The best practices for use of this methodology and the associated uncertainty are detailed in the full-length paper. The challenge in characterizing layered reservoirs is the large number of unknown parameters. The approach described in the paper resolves enough of these unknowns in a systematic fashion for a more direct solution to be obtained, with a resulting lower uncertainty. Tengiz Field The central platform of the Tengiz carbonate reservoir is dominated by matrix porosity. The surrounding rim and flank regions exhibit evidence of fracture networks. Three major zones contribute to oil production. The upper reservoir units have been produced for a longer period of time and, therefore, are more depleted. All Tengiz wells are essentially vertical and are producing single-phase oil with flowing bottomhole pressure above the bubblepoint, which provides good conditions for production-log profiling. Because most wells produce no water, the connate water has low salinity, and irreducible water saturation is approximately 10%, elevated chlorine-concentration levels remained in the near-wellbore region of the formation after acid stimulation, which increased the chance for a PNC log to detect acid effects. Sour-gas injection for miscible flooding began in late 2007 in the central-platform area. Understanding individual-zone formation properties was important in the success of the hydrocarbon-miscible flood.

Optimization of Production Performance in a CO2 Flooding Reservoir Under Uncertainty

Abstract CO2 flooding has gained momentum in the oil and gas industry and might be suitable for approximately 80% of oil reservoirs worldwide based on the oil recovery criteria alone. In addition to miscibility, production performance needs to be optimized to achieve higher sweep efficiency and oil recovery. Although many techniques have been made available for production optimization in the upstream oil and gas industry, it is still a challenging task to optimize production performance in the presence of physical and/or financial uncertainties. In this paper, a new technique is developed to optimize production performance in a CO2 flooding reservoir under uncertainty. More specifically, potential uncertainties influencing production performance are analyzed and assessed by using the geostatistical technique. This enables us to integrate the available information within a unified and consistent framework and to generate multiple geological realizations accounting for uncertainty and spatial variability. Subsequently, the net present value (NPV) is selected as the objective function to be optimized by using the genetic algorithm, while well rates of the injectors and the flowing bottomhole pressure for the producers are chosen as the controlling variables. In addition, corresponding modifications have been made to accelerate the convergence speed of the genetic algorithm. A field case is used to demonstrate the procedures of the newly developed technique and the optimized results show that the oil recovery and the NPV can be increased by 6.4% and 9.2%, respectively. It is also found that the genetic algorithm is a powerful and reliable search method to optimize production performance of reservoirs with complex structures. Introduction CO2 flooding is considered as a promising and practical enhanced oil recovery (EOR) process because it not only increases oil recovery, but also reduces greenhouse gas emissions by sequestrating CO2 in the depleted reservoirs. In practice, CO2 flooding performance can be greatly affected by the reservoir heterogeneity, which can severely reduce the sweep efficiency, result in early CO2 breakthrough at the producers, and thus, leave a large amount of bypassed oil in the reservoir(1). Therefore, it is of fundamental and practical importance to optimize production performance of a CO2 flooding reservoir.

Well-Test Dynamics in Rich-Gas/Condensate Reservoirs Under Gas Injection

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 121848, ’Well-Test Dynamics in Rich-Gas/Condensate Reservoirs Under Gas Injection,’ by O.A. Aluko, SPE, and A.C. Gringarten, SPE, Imperial College London, prepared for the 2009 SPE Europec/EAGE Annual Conference and Exhibition, Amsterdam, 8-11 June. Well-test behavior of rich-gas/condensate reservoirs with pressure below the dewpoint pressure was studied to analyze revaporization of the condensate bank upon repressurization by gas injection. Compositional-simulation results suggested that the near-wellbore fluid saturation below the dewpoint pressure in a buildup is different from that at the end of the preceding drawdown because of significant differences in fluid properties and saturation distributions. A method was proposed to evaluate the bank storativity, which then is used to calculate the bank radius. Introduction Rich-gas/condensate reservoirs are characterized by a high liquid-hydrocarbon yield and often are developed for their liquid reserves. Compared to lean-gas condensates, rich-gas condensates have a higher percentage of intermediates and C7+ components, higher specific gravity, and lower gas/oil-ratio (GOR). Often, guidelines used to distinguish rich-gas condensate are an initial producing GOR of 3,300 to 5,000 scf/STB, heptanes-plus concentrations of approximately 12.5%, maximum liquid drop-out up to 35%, and an initial liquid yield greater than 100 STB/MMscf. Rich-gas/condensate reservoirs challenge fluid characterization and well-test analysis because of their near-critical nature. A unique problem in reservoir development is the result of condensate deposit at pressures below the dewpoint pressure and the creation of a condensate bank that decreases productivity and may result in a potentially significant loss of liquid reserves. Rich-gas/condensate reservoirs often are developed with secondary- or enhanced-oil-recovery methods to maximize liquid recovery. It is vital to monitor and understand the behavior of the two-phase condensate bank during production when assessing its effect on productivity and ultimate recovery. Gas injection into rich-gas/condensate reservoirs attempt to maintain the average reservoir pressure (and possibly the flowing bottomhole pressure) above the dewpoint pressure. Injecting gas below the dewpoint pressure can improve condensate recovery by displacing condensed liquids toward producing wells and vaporizing the intermediate and heavy components of the condensate. As detailed in the full-length paper, time-lapse well-test-pressure derivatives can be used to monitor changing fluid saturations in these reservoirs. Well-Test Dynamics Below the Dewpoint Pressure Compositional simulation was used to investigate and characterize reservoir-fluid dynamics and well-test behavior in rich-gas/condensate reservoirs. The thermodynamic properties of the fluids were represented by modified Peng-Robinson equation of state (EOS), with EOS parameters based on experimental data from the MTGc reservoir in north Africa. Velocity-dependent parameters matched to multirate-well-test data were included in the numerical modeling. The study focused on the effects of the following.

Downhole Gas Compression: A New Artificial-Lifting System for Gas Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 121815, "Downhole Gas Compression: World's First Installation of a New Artificial-Lifting System for Gas Wells," by M.T. Di Tullio, SPE, S. Fornasari, and D. Ravaglia, Eni SpA E&P Division, and N. Bernatt, SPE, and J.E.N. Liley, SPE, Corac Group plc, originally prepared for the 2009 SPE EUROPEC/EAGE Annual Conference and Exhibition, Amsterdam, 8-11 June. The paper has not been peer reviewed. Downhole gas compression (DGC) is a new artificial-lift technology designed specifically for natural-gas wells and is an as yet unrealized opportunity within the upstream gas industry. The technology offers the opportunity to increase production by 30 to 50%, improve reserves significantly, and delay the onset of liquid loading. Although it can be used at any time during the life cycle of a gas asset, it will find particular favor during the decline phase. Introduction The upstream gas industry often is faced with the challenge of selecting an optimum artificial-lift system from various alternatives available for gas-well production enhancement. These challenges become more complex with increasing dynamic changes in well flow characteristics over the life of the well. Application of DGC technology in suitable wells offers value for the following reasons.Acceleration of early production and extension of production plateau in new gas developments.Cost-effective rejuvenation of mature gas reservoirs characterized by low reservoir pressure and liquid accumulation in wells.Improvement of gas-well production and maximization of recovery factor from gas reservoirs with low environmental impact.Identification of incremental reserves and for monetization of stranded gas. As part of an ongoing development through a joint-industry program, the first field trial of the new technology was conducted in an onshore gas well. The program has been completed in phases, including the design, building, and testing in a full-scale flow loop that closely replicated downhole conditions. The prototype has been tailored to suit the expected gas-flow range, composition, and condition of the selected field-trial well. Fig. 1 shows an internal view of one of the three compressor modules, with the gas path indicated in red. Why Compress Gas Downhole Operators of a producing asset always are seeking to maximize its value. In natural-gas fields, optimum gas production at low intervention cost and frequency is the ultimate objective in gas-well production management. To maximize production, the flowing bottomhole pressure (FBHP) should be kept as low as operationally possible. There are many challenges to achieving this objective.

Two-Phase Flow in Volatile Oil Reservoir Using Two-Phase Pseudo-Pressure Well Test Method

Abstract When the bottomhole pressure (BHP) of volatile oil reservoirs falls below the bubblepoint pressure, two phases are created in the region around the wellbore, and a single phase (oil) appears in regions away from the well. The oil relative permeability reduces towards the near-wellbore region due to increasing gas saturation. This behaviour is quite similar to a gas-condensate reservoir below the dew-point, where the gas relative permeability is reduced due to the existence of a liquid bank around the wellbore. There are numerous publications in the literature concerning the behaviour diagnostic and well deliverability calculation in the case of gas-condensate reservoirs. However, the behaviour of volatile oil reservoirs is not well understood. This paper aims at understanding the behaviour of volatile oil reservoirs. We used reservoir compositional simulations to predict the fluid behaviour below the bubblepoint, and then exported the flowing bottomhole pressure to a well test package to diagnose the existence of different mobility regions. In this study, the applicability of the two-phase pseudo-pressure method on volatile and highly volatile oil reservoirs was investigated, and it was found that this method is a very powerful tool for the prediction of true permeability and mechanical skin. Also, this method is capable of distinguishing between mechanical skin and condensate bank skin, which can be very helpful for designing after-drilling well treatment and IOR process designs. Introduction In gas-condensate reservoirs, retrograde condensation occurs when the flowing bottomhole pressure declines below the dew-point pressure, creating four regions in the reservoir with different liquid saturations. Away from the well, an outer region has the initial liquid and gas saturation. Next, nearer the well, there is a rapid increase in liquid saturation and a decrease in the gas mobility where the liquid still is immobile. Closer to the well, an inner region is formed where liquid saturation is higher than the critical condensate saturation and both oil and gas phases are mobile. Finally, in the immediate vicinity of the well, there is a region with a lower liquid saturation due to capillary number (the ratio of viscous to capillary forces) effects. Such a region has been inferred from a number of experimental core studies at low interfacial tension and high flow rates. The existence of the fourth region is important because it counters the reduction in productivity caused by liquid drop-out. The various mobility zones described above can be identified by well test analysis, using a variety of analytical and numerical models(1–3). Well test analysis is now commonly used to identify and quantify near-wellbore effects, reservoir behaviour (i.e. zones of different mobilities and storativities) and reservoir boundaries. Finding all of this information from well tests in gas-condensate reservoirs, however, is challenging. This is due to changes in the composition of the original reservoir fluid and the impact of wellbore dynamics. Nonetheless, gas-condensate flow behaviour is now reasonably well understood.