Managing adequately pressure drawdown should be a key technical reservoir management driver due to its major impact on cash flow, acceleration and final recovery factor for operating hydraulically fracture shale gas condensate producers. Permeability should be regarded as a key dynamic property for ultra-low permeability shale reservoirs that influences shale hydrocarbon recovery. It is paramount to develop a pressure depletion plan that captures the pressure drawdown strategy and the changes in flow capacity associated to the interaction of the nano-Darcy rock and hydraulic fractures with stress dependent permeability effects.
Defining the adequate drawdown strategy would aid maximizing the economic recovery. Considering the variability of permeability with pressure drawdown should be part of the reservoir management lifecycle for unconventional shale reservoirs. This study focus on evaluating the impact of pressure drawdown strategy on initial rates and recovery for a Duvernay Gas condensate producer with an initial condensate yield of 100-150 stb/mmscf.
A sector compositional reservoir simulation model was built for a horizontal multistage hydraulically fracture Duvernay shale gas condensate producer. A full assessment of variability of permeability in the nano-Darcy rock and in the propped hydraulic fracture stages near the wellbore region was accomplished. Aggressive, moderate and conservative pressure drawdown strategies were evaluated, considering multiple operational pressure drawdown incremental ranges from 14.5 to 95 psia per day.
Results clearly indicate that implementing daily pressure drawdown increments of 22 to 29 psia per day would provide a similar recovery factor than imposing daily pressure drawdowns of 44 to 95 psia per day. However, there is a golden operating window opportunity to accelerate recovery by imposing maximum drawdown from the early days of production and bringing significant benefits of accelerating recovery with an associate increase in revenue but the benefits of this acceleration vanished in less than one year due to substantial changes in hydraulic fracture conductivity and also in the nano-Darcy rock permeability in the near wellbore region. The reduction of nano-Darcy permeability is a function of pressure, time and distance from the hydraulic fractures. According to our results, the best reservoir management practice for operating lean/medium Gas Condensate unconventional shale producers should be maximizing pressure drawdown at the early stage of the life cycle and deferring the installation of production string to maximize inflow-outflow.
Unlike conventional reservoir development, uncertainty analysis and design optimization of unconventional reservoirs have caught less attention because of a general notion that oil field production data analysis and computational methodologies and techniques can be applicable to unconventional reservoir developments. In order to predict production profiles in unconventional reservoirs, it is essential to understand the uncertainties and performance of unconventional reservoirs. In this paper, the most relevant factors influencing the production of gas-condensate in a domain of real data from gas condensate fields is investigated and reviewed. To identify the major factors affecting the production of condensates from heterogeneous and ultra-low permeability reservoirs, third and fourth order factorial design (Box Behnken technique) were used on a domain of gas-condensate field data to perform the uncertainty analysis. A semi-analytical surrogate model for Monte Carlo analysis was also proposed in this paper. Condensate blockage radius, reservoir permeability, well spacing, reservoir thickness; compressibility, initial pressure; fracture spacing and initial condensate saturation were noted to be the most substantial parameters influencing condensate production. Validation of the results proved that the proposed surrogate models for gas-condensate reservoirs could reliably be used to forecast condensate values in heterogeneous and ultra-low permeability reservoirs. This paper also presents a semi-analytical model applicable to unconventional reservoirs to incorporate the effect of condensate banking in the design optimization of hydraulic fracturing. Analytical models for Darcy flow above and below the dew point pressures were considered whilst estimating the optimum fracture design in gas condensate reservoirs using Schechter's approach incorporating the effects of the condensate blockage radius.
This paper presents a method for the fast evaluation of fracture-stimulated condensate reservoir economics. For the calculation of production decline in such reservoirs, an efficient numerical model with a three-phase transient analysis of pressure distribution was built and validated using the predictions from reservoir solvers and field data. This model solves for gas-, oil-, and water-flow parameters, accounting for the gas-oil phase transition, and has been realized in a numerical code and compared with predictions from commercial software and available field data, such as production-decline curves.
The developed numerical model has been implemented in commercial software and used for the sensitivity analysis of reservoir productivity regarding changes of fracture size and spacing, as well as reservoir permeability in the fractured condensate reservoirs, with an account for multiphase reservoir flows and reservoir properties. A side-by-side comparison of predictions from two commercial reservoir simulators has shown that that this model accurately calculates transientpressure fields near the fractures and the productiondecline curve.
The objective of the economic analysis and fracture optimization stage is reduced to finding the target function minimum in an
Horizontal wells with multistage hydraulic fractures have become the most common practice to obtain viable commercial production from shale and tight gas reservoirs. With a marked increase of gas production emerging from these tight reservoirs, it is necessary to further study the effects of formation damage due to condensate dropout and how best to prevent and mitigate this damage. There are two common ways to mitigate and treat condensate banking. The first method is to fracture the existing well. This allows bypassing the condensate and therefore increasing well productivity. The second method is to shut-in the well and allow pressure to build up so that the dropped out liquids are revaporized back into the gas. These options, respectively, involve large capital expenses and temporary decrease of production. Before deploying these solutions, the condensate dropout damage can be strongly reduced at no (field) cost by optimizing the well location.
This objective in this study was to determine the optimum well location to mitigate formation damage due to condensate dropout in a tight gas well. Compositional reservoir simulations were conducted with different condensate gas ratios and relative permeability curves to quantify the loss of productivity due to formation damage under different conditions. The target formation was 100 ft thick, and a tartan grid was used to represent the hydraulic fractures within the tight gas well.
This study determined that well placement plays a key role in preventing damage due to condensate banking. The optimized placement of the well can drastically enhance the viability of a project by allowing for a larger recovery.
Development of liquid rich shale (LRS) reservoirs has gained tremendous momentum in recent years. A detailed understanding of fluid behavior, completion practices and reservoir dynamics is essential to accurately predict their long-term performance. This paper uses stochastic reservoir modelling to identify the optimal values for several completion and uncertainty parameters.
A compositional reservoir simulation model for a typical gas condensate well in the Eagle Ford shale was used to identify the optimal production strategies for maximum EUR of oil and gas. The important factors considered for the study are fracture spacing, fracture conductivity, fracture half-length, well spacing, porosity, permeability, initial GOR and well constraints. These factors are often studied independently of one another and their interaction is usually ignored. For example, in a higher permeability play, greater fracture density leads to rapid recovery but ultimate cumulative production does not improve. However, for a play with lower permeability, greater fracture density improves both recovery rate and EUR thereby leading to improved overall economics. Thus, interaction effects due to coupling can have a decisive effect on the overall performance of a reservoir. This paper presents a statistical study of both independent and coupled effects on ultimate oil and gas production from a LRS gas condensate reservoir.
The results show that fracture half-length and fracture spacing have the most complex and significant effects on performance of the reservoirs studied. High initial rates are often preferred in unconventional reservoirs with their rapid rates of decline. These high rates can be achieved with larger fracture half-lengths and smaller fracture spacing. This study shows that high initial rate of production leads to a greater liquid dropout and larger condensate banking. These results also reduce the production rate of gas due to relative permeability effects. Return on investment is reduced due to reduced cumulative production and excess spending on fracture creation. Similar effects were observed for other factors like well constraints where higher minimum flowing bottom-hole pressure led to lower cumulative gas production and lower liquid dropout. In some cases higher bottom-hole pressure might be preferable due to the differential in the price of condensate and gas.
The sensitivity studies in this study provide considerable insight into the long-term production behavior in LRS gas condensate reservoirs. During the initial phase of a project, uncertainties related to various field parameters and their coupled effects are often ignored leading to suboptimal returns on investment.
The chemical treatment using surfactants/solvents can mitigate the liquid block by wettibility alteration in gas/condensate wells. Recently, its application has been extended from wettibility change in matrix to wettibility alteration in propant in hydraulic fractures and tested in field trials. The leak-off of working fluids into matrix may mitigate the liquid block in the matrix adjacent fracture walls unintentionally. However, it is not clear yet whether the mitigation in matrix from leak-off is significant, compared with the mitigation in the fracture propant, and how this may affect the job design. The experimental setup and associated results was for assessment of the treatment in fracture propant only. In the lab, the leak-off will not affect the flow in fracture since hydrocarbon is injected along the fracture to simulate the production. In reality, the hydrocarbon produce passing through the matrix blocks along fracture. And all previous modeling study and job design has ignored the leak-off. This work shows by simulation of a generic case how the leak-off may affect the design and outcome of the treatment.
This work clarifies several important design concerns for the chemical treatment in hydraulic fractured reservoir, which may be extended to natural fractured reservoir as well. This will affect the optimal treatment volume, prediction of outcome and economic evaluation. The leak off may bring little extra benefit from the removal of the block in matrix along fracture walls. But such extra benefit is not significant compared with that in the fracture propant. Due to leak-off, the treatment volume based on fracture volume is not adequate and the associated outcome prediction is optimistic. There is an optimal treatment distance along with fracture that had not been identified in previous study. There is not need to treat the fracture at its full length. Just the opposite, with leak off accounted for the attempt to treat the whole fracture will cost huge volume of working fluid and lead to extra liquid damage. The unintentional matrix treatment due to leak off will cost much more working fluid than the fracture treatment. Therefore, it is necessary to optimize the treatment volume during the job design.
Chemical treatment to remove liquid block in matrix and in hydraulic fracture
Li and Firoozabadi (2000) proposed an approach for stimulating gas condensate wells by changing the rock wettability towards non-liquid wetting in the near well-bore region. Kumar et al. (2006) reported improvement in gas and condensate relative permeability when Berea and reservoir sand stone cores were treated using a non-ionic surfactant. Bang et al. (2007) did extensive experiments for sandstone with a variety of new solvents containing a fluorocarbon polymeric surfactant. Ahmadi et al. (2010) reported successful wettability alteration in Texas Cream limestone and Silurian Dolomite cores. Effective solvent mixture was developed for delivering fluorinated chemical to the rock surface.
Shandrygin, Alexander (Schlumberger) | Dinariev, Oleg (Institute of Physics of Earth, RAS) | Rudenko, Denis (Schlumberger) | Tertychnyi, Vladimir V. (Schlumberger) | Evseev, Nikolay (Institute of Physics of Earth, RAS) | Klemin, Denis (Schlumberger)
High accurate reservoir simulation is required to better describe multiphase fluids flow to hydraulic fractured wells and improve the development of gas-condensate field. In recent years, numerous research efforts were focused on the developing efficient numerical scheme for full-field simulation and have been facing the problem of tremendous computational resources used to simulate realistic hydraulic fracture details for better and more reliable production optimization. Most of the existent numerical models are based on 3D computational grid that is used for the whole reservoir with grid refining in fracture domain and couldn't completely account all phenomenon within reasonable computational time.
New approach for simulation of multiphase multicomponent steady state flow around the hydraulic fractured well is proposed. The approach is based on the splitting the thermodynamic and hydrodynamic problems of multiphase and multicomponent fluids flow. It is also assumed that conductive fracture could be described by 2D surface in 3D permeable formation. Additional coordinate system inside fracture allows to simulate the heterogeneous internal structure of fracture and account the details of the exchange process between fracture and reservoir. Relative permeability and non-Darcy effects in fracture and formation and non-uniform fracture conductivity could be taken account as well.
Proposed model can be used for simulation of the steady-state multiphase multicomponent flow to hydraulic fracture of any arbitrary shape. Excellent agreement with commercial dynamic simulators was achieved for gas condensate flows simulation. Significant decrease in computational time in comparison with the existent simulators had been achieved.
Gas condensate reservoirs usually exhibit complex flow behaviors due to thebuild-up of condensate banks around the wells when the bottomhole pressuredrops below the dew point. The liquid phase accumulation in the near-wellboreregion forms a ring that reduces the gas relative permeability. As a result,gas production decreases and the liquid phase which is a significant part ofthe value of the field remains in the reservoir.
Various solutions have been implemented in order to remediate such aproductivity loss. They include drilling horizontal wells instead of verticalwells[1-3], hydraulically fracturing vertical wells before or after thedevelopment of the condensate bank, and acidizing after the condensate bank hasformed[4-14].
In this work, we used reservoir simulation to quantify the increase in wellproductivity from different remediation solutions and assess theireffectiveness. The empirical correlations needed to model non-Darcy flow andcapillary number effects, which are among the main parameters that control gascondensate well performance, were calibrated with actual well testdata.
As should be expected, we found that horizontal wells and hydraulicallyfractured vertical wells improve well productivity. The degree of productivityenhancement, however, depends on well and reservoir parameters such ashorizontal well lengths, permeability anisotropy, fracture length and fractureconductivity. Different simulation models were run above and below the dewpoint pressure at the same reservoir and flow conditions. The results of oursimulations show that horizontal wells enhance productivity significantly belowthe dew point. Performance improvement with hydraulic fractures, on the otherhand, depends on facture length and fracture conductivity.