Wells in high permeability reservoirs requiring sand control are commonly completed either with a high permeability fracture (HPF) or a high rate water pack (HRWP). These prolific reservoirs are capable of delivering high production rates, but the downhole flow velocity becomes a limiting factor. The downhole velocity is one of the most important factors in completion failure. To determine a safe producing rate for prolific wells, the current best practice is to monitor flux to avoid completion failure due to screen erosion or destabilization of the annular pack. Flux is the flow velocity at a critical location in the completion: at the screen face to avoid screen erosion, or in the annular pack to avoid pack destabilization. The commonly applied method for mathematically estimating the flux from the mechanical skin relies on a number of parameters that cannot be uniquely quantified, including the proppant permeability, the proppant turbulence factor, and the fracture skin. The calculated flux is highly sensitive to these uncertain parameters. When the flux is overestimated, the well rate will be unnecessarily restricted. Underestimation of the flux risks completion failure. Most practitioners assume values for uncertain parameters, calculate the flux, and back-calculate the number of flowing perforations. Sensitivity studies will show the potential pitfalls of this technique. Instead, this paper presents an alternative approach to determine the flux as the total flow rate divided by the flow area, which, in turn, can be related to the number of perforations effectively conducting fluid from the reservoir to the wellbore. For the HPF case, this means how many perforations connect the fracture to the wellbore, which is a function of the angle between the well trajectory and the far field plane of the hydraulic fracture. When the angle cannot be determined due to a lack of the necessary stress measurements or stress isotropy, the flux will be calculated based on the pressure drop across the perforation tunnels obtained from the mechanical skin. The method and its advantages over existing techniques will be demonstrated using field data from deepwater Gulf of Mexico (GOM) wells. Introduction When wells are drilled at an inclination, the intersection between a vertical fracture and the wellbore may be extremely limited and may complicate treatment execution and further restrict well productivity (Martins et al. 1992). In one reservoir, efforts to improve wellbore to fracture connectivity in deviated wells including 180 degree phased, oriented perforations, and aggressive tip screen out designs with high conductivity proppant were shown to compensate for these problems (Vincent and Pearson, 1995). However, superior treatment execution and well production are often achieved when fracturing vertical wells rather than inclined wells.

Wells in high permeability reservoirs are frequently constructed with deviated wellbores completed with a high permeability fracture (HPF). If the deviated well is not drilled perpendicular to the minimum horizontal stress, significant misalignment between the wellbore and the fracture plane is likely to occur. In turn this leads to limited communication between the fracture and the wellbore, resulting in a reduced number of flowing perforations and additional pressure drop. In low permeability reservoirs, even for a misaligned fracture the majority of the flow is through the hydraulic fracture. In contrast in deviated HPF wells a significant flow contribution may be through the gravel pack (GP) perforations that are not connected to the fracture, thus bypassing the fracture. The flow fraction bypassing the fracture depends on the formation permeability and the fracture and gravel pack skins. This paper will show that the conventional inflow performance calculations cannot be applied for a HPF well with a misaligned fracture. It is generally incorrect to treat the inflow performance for a deviated HPF well in the same manner as for a vertical well. This paper provides a semi-analytical model for the flow pattern taking into account both flow to the fracture and flow that bypasses the fracture to the GP wellbore region. The model shows that the limited communication between hydraulic fracture and wellbore has a great impact on the entire flow pattern. A field example with a deviated deepwater well (DW) from the Gulf of Mexico (GOM) will be shown. The flux method will be revised taking into account flow contribution from the GP region, resulting in additional flow perforations but adding more risk for fines movement and skin increase. Introduction Veeken et al. (1989) explained the importance of drilling vertically through the productive reservoir interval when the intent is to hydraulically fracture the well. Ehlig-Economides et al. (2008) and Tosic et al. (2008) introduced a new geometric model for hydraulically fractured wells hypothesizing that only those perforations in the intersection between the far field hydraulic fracture plane and the wellbore actually connect flow through the fracture to the well. According to the geometric model, in deviated wells the number of perforations connected to the fracture drops to a small value for even moderate well deviation angle, and the skin computed using the model compares favorably with field data observations without resorting to assuming a small value for the proppant permeability. In contrast Wong et al. (2003), rely on an assumed fracture skin to estimate mechanical skin dominated by pressure drop in the perforations from pressure transient data, calculates the velocity through perforation tunnels consistent with the observed mechanical skin pressure drop, and in turn back calculates the number of perforations consistent with the computed velocity. While the geometric model determines the number of flowing perforations strictly by geometry with no assumed values, the Wong et al. (2003), estimate for the number of perforations is highly dependent on the assumed values for proppant permeability and beta factor and mechanical skin. Tosic, et al. (2008) showed wide variations in the values for proppant permeability and beta factor that may apply, and pointed out that the mechanical skin is difficult to quantify because the total skin determined from pressure transient analysis (PTA) includes the sum of the mechanical skin and a negative fracture equivalent skin that is seldom possible to quantify because the fracture flow regimes are masked by wellbore storage. The potential consequence of the surmised geometry of flow is that deviated wells producing at high rate may have exhibit very high velocity through the few perforations connecting the fracture to the wellbore, thereby risking screen erosion or GP destabilization. However, Norman (2003) reported that HPF completions have shown much better long term performance than GP completions. Since many deviated, high rate wells have HPF completions, the geometric model suggests there should be more HPF well completion failures than have been observed.

Operators, especially those managing production from deepwater reservoirs, are striving to produce hydrocarbons at higher and higher rates without exposing the wells to completion failure risk. To avoid screen failures, recent studies have favored high rate water pack (HRWP) completions over high-permeability fracturing (HPF), known in the vernacular as a frac&pack (FP) for very high rate wells. While a properly designed gravel pack (GP) completion may prevent sand production, it does not stop formation fines migration, and, over time, fines accumulation in the GP will lead to increasing completion skin. Although, and not always, the skin can be removed by acidizing, it is not practical to perform repeated acid treatments on deepwater wells, particularly those with subsea wellheads, and the alternative has been to subject the completion to increasingly high drawdown, accepting a high skin effect. A far better solution is to use a HPF completion. Of course the execution of a successful HPF is not a trivial exercise, and frequently, there is a steep learning curve for such a practice. This paper explains the importance in HPF completions of the well trajectory through the interval to be hydraulically fractured, for production, not execution, reasons. A new model quantifies the effect of the well inclination on the connectivity between the fracture and the well via perforations both in terms of the total skin and the screen flow velocity. Guidelines are provided based on the maximum target production rate, including forecasts of multiphase flow, to size the HPF completion to avoid common completion failures that may result from high fluid rate and/or fines movement. Once the HPF is properly designed and executed, the operator should end up with a long term low skin good completion quality well that can be safely produced at the maximum flow rates, with no need for well surveillance and monitoring. Introduction The rationale for sand control completions is to prevent production of fines into the well. Given the high well costs in deepwater reservoir developments, profitability requires the wells to be produced at high rates, up to 40,000 STB/D for oil wells and 100 MMSCF/d for gas wells. Typically the reservoirs are capable of delivering the high rates, provided the well completions do not fail. Operators dealing with subsea flowlines cannot tolerate even minimal fines production. Reasons include the possibility of fines build up, erosion of subsea chokes and hardware, and in severe instances even flowline plugging. Complex flow assurance measures only make the situation worse. Remediation of any of these problems would require an expensive workover. The current emphasis in the literature is on controlling the well flow rate to avoid exceeding estimated velocity or drawdown limits. This is a form of sand management when what is really needed is reliable sand exclusion at target production rates. Veeken, et al.1 emphasized the importance of close alignment between the wellbore axis and the far field fracture plane. Unless the well is deliberately drilled to align with the fracture plane, their experiments showed that the well would have limited entry effects and reduced productivity due to poor communication between the wellbore and the hydraulic fracture. They stated that communication between the fracture and wellbore is determined by the orientation of the wellbore and perforations with respect to the in-situ stresses. There is also a possibility of forming of multiple fractures. Furthermore, they did a combined theoretical and experimental study to investigate key parameters for well-to-fracture connectivity. A key conclusion in the work by Veeken, et al.1 was a recommendation that the wellbore trajectory be drilled to align normal to minimum horizontal stress, either by drilling vertically through the productive interval or by turning the inclined well to this alignment. Since then many operators and service providers have rejected the Veeken, et al.1 advice for various reasons. Cleary, et al.2 have recommended pumping strategies that tend to avoid multiple fractures. Also, many of the operators simply overlook altogether the importance of the well trajectory. Furgier, et al.3 boast that they were able to place high permeability fracture planes in highly deviated wells, as though that were the sole objective, but they also report skins that are consistently well above zero. Furthermore, Furgier, et al.3 concluded that FP completions are common practice in 65° deviated wells and good completion efficiency is achieved (mechanical skin less than 5).

Experience shows that high-performance fractures (HPFs) may retain near-unit-flow efficiency (equivalent to zero skin in a vertical well) and rarely fail, even in highly deviated wells. This may be partly because overly simplistic models of the well flow behavior lead operators to maintain wells at lower production rates than could have been achieved for the same amount of injected proppant with a vertical-well-completion design. Rigorous models that account for widely accepted rock-mechanics fundamentals indicate that the fracture-to-well connection is compromised in deviated wells and lead to questions concerning whether the bulk of the flow to the well actually passes through the fracture.Distributed volumetric sources are used in this model to rigorously model a wide variety of possible fracture geometries such as an expanded wellbore because of halo effect, flow strictly through the fracture, and combined flow through a single fracture and to remaining flowing perforations not connected to the fracture. The model also includes turbulent-flow effects that may occur for radial-flow conditions in the fracture plane or in the reservoir opposite wellbore sections not connected to the fracture, along with high-velocity flow through the perforation tunnels. It also computes the effective flow area at the resulting face between the reservoir and the completion to check whether flow velocity exceeds conditions that would risk production of reservoir fines, and it estimates the screen-flow velocity on the basis of the number of flowing perforations.This comprehensive view of the HPF completion enables a thorough analysis of the risks of flowing the well at high rate. Field examples show that the new model depicts real field conditions in calculating the total skin, flow fractions, and the flux for HPF completions in high-rate gas and oil wells.Complete inflow-performance behavior for likely flow patterns for HPF wells in oil and gas reservoirs is provided.

In a carbonate field, a gas injection scheme has been assessed to improve oil recovery through pressure maintenance and miscible displacement. The potential study assumed sequential application of several gas injection concepts: Raw Gas Injection (RGI) and Acid Gas Injection (AGI). Flow simulation studies of these concepts revealed a variety of compositional changes to the in-situ fluid depending on the injection scheme and composition of the injected gases. Compositional change is a common trigger of asphaltene instability; therefore, to ensure a robust gas injection development, it is important to evaluate the risk of asphaltene deposition. Due to high H 2 S concentrations in potential developments, it is difficult to take an experimental approach for evaluating gas-mixed asphaltene flow assurance. Hence, this paper will focus on one AGI scenario, and present how AGI impacts asphaltene precipitation behavior through numerical modeling analysis. Based on the asphaltene model established by applying Cubic Plus Association (CPA) equation of state (EoS), which was calibrated with the experimental measured asphaltene onset pressure (AOP), a new Binary Interaction Parameters (BIP) correlation between H 2 S and hydrocarbons was incorporated to evaluate variation of asphaltene precipitation envelope (APE) with periodical compositional change observed from the AGI flow simulation. Acid Gas (AG) was assumed to be 90mol% H 2 S and 10mol% CO 2 . The produced fluid H 2 S concentration used in this study was assumed to be~15mol%. During this study, H 2 S concentration was observed to increase up to 76mol% at a well located near AG injectors after long term flow simulation. In the APE sensitivity analysis that was independently conducted for each composition of H 2 S and CO 2 , the asphaltene model revealed the base APE shrunk as the H 2 S concentration increased while it expanded as the CO 2 concentration increased. As a result for the mixed compositions, the opposing effects on the APE offset each other; the AG addition produced a subsequent shrinking of the APE. In summary, this work supported acid gas injection from a thermodynamically asphaltene flow assurance point of view.