Comparative Evaluation of Gas-Condensate Enhanced Recovery Methods for Deep Ukrainian Reservoirs: Synthetic Case Study

2021 ◽  
Author(s):  
Oleksandr Burachok ◽  
Oleksandr Kondrat ◽  
Serhii Matkivskyi ◽  
Dmytro Pershyn
Keyword(s):  
Enhanced Recovery ◽  
Economic Effect ◽  
Gas Condensate ◽  
Dew Point ◽  
Rapid Screening ◽  
Gas Mixture ◽  
Reservoir Pressure ◽  
Compositional Simulation ◽  
Gas Condensate Reservoirs ◽  
Gas Recovery

Abstract Low value of final condensate recoveries achieved under natural depletion require implementation of enhanced gas recovery (EGR) methods to be implemented for the efficient development of gas-condensate reservoirs. The study was performed using synthetic numerical 9-component compositional simulation model that approximated the typical conditions of deep gas-condensate reservoirs of Dnieper-Donetsk Basin in Easter Ukraine. Injection of water, methane, nitrogen, carbon dioxide, mixture of methane and nitrogen, mixture of methane, ethane and propane at different concentrations were evaluated at 50% and 100% voidage replacement for reservoir fluids with 100 g/m3, 300 g/m3 and 500g/m3 potential condensate yield. Condensate recovery studied at different stages after primary depletion, when reservoir pressure reached 25, 50, 75% from dew point and at pressure of maximum liquid dropout. Results comparison was done based on the two criteria: technical efficiency – incremental condensate recovery towards the base depletion cases and economic efficiency – cumulative NPV. Status of initial depletion as well as voidage replacement have a direct impact on breakthrough time and negative economic indicators. Despite providing the highest incremental condensate recovery by injecting CO2 at 100% voidage, it has a strong negative economic effect. Based on incremental condensate recovery EGR methods are ranked as following for all condensate potential yields and levels of primary depletion: CO2 100%; solvent gas mixture of C1 90%, C2 5%, C3 5%; solvent gas mixture C1 98%, C2 1%, C3 1%; C1 100%; mixture of C1 50% and N2 50%; N2 100%; water. Economically, the highest efficiency was shown for C1 100% injection, due to the fact, that produced re-cycled gas has a sales value as well. For the maximum incremental recovery it is advisable to start the injection as early as possible, while highest economic increments received for the cases of delayed injection, particularly when the reservoir pressure is equal to the pressure of maximum liquid condensation. The results of study can be used a guidance for rapid screening of applicable EGR method for gas-condensate fields depending on depletion stage and potential condensate yield.

Condensate Recovery from Tight Gas-Condensate Reservoirs using a new Method Based on a Gas-Based Chemical

2021 ◽  
Author(s):  
Abdulelah Nasieef ◽  
Mahmoud Jamiolahmady ◽  
Hosein Doryanidaryuni ◽  
Alejandro Restrepo ◽  
Alonso Ocampo ◽  
...  
Keyword(s):  
Enhanced Recovery ◽  
Gas Condensate ◽  
Dew Point ◽  
New Method ◽  
Reservoir Rock ◽  
Production Data ◽  
Low Permeability ◽  
Recovery Method ◽  
Gas Condensate Reservoirs ◽  
Hydrocarbon Gas

Abstract Recovery from gas condensate reservoirs, when the pressure is below dew point pressure (Pdew), is adversely affected by the accumulation of condensate in the near wellbore region. The mitigation of the near-well bore condensate banking is the main purpose of any enhanced recovery method implemented in gas condensate reservoirs. In this work, a new method was tested to improve condensate recovery by using a chemical that was delivered using hydrocarbon gas as a carrier into a very low permeability and very low porosity reservoir rock. Chemicals are typically injected using liquid carrier solvents. The use of hydrocarbon gas as the carrier provides a remedy to mitigate condensate banking in very low permeability cores by minimizing complications associated with low injectivity and back flow clean-up process requirements of an injected liquid. The chemical potential was evaluated by recording production data from unsteady-state coreflood experiments. The injection of the chemical with equilibrated gas resulted in condensate saturation to decrease from 19.6% to 6.5%. This decrease was not instantaneous and took some time to occur indicating that the chemical needs time to interact with the resident fluid and rock. The benefit of the method, at the field scale, was also estimated by performing single-well numerical simulations that use relative permeability (kr) data which history matched the measured coreflood production data. The results of these preliminary simulations also showed improved recovery of gas and condensate compared to pure depletion, without chemical, by around 40% for the cases considered.

scholarly journals Investigation of the efficiency of gas condensate reservoirs waterflooding at different stages of development

2021 ◽  
Vol 230 ◽  
pp. 01010
Author(s):  
Oleksandr Burachok ◽  
Oleksandr Kondrat ◽  
Serhii Matkivskyi
Keyword(s):  
Water Injection ◽  
Gas Condensate ◽  
Dew Point ◽  
Recovery Factor ◽  
Rapid Screening ◽  
Final Decision ◽  
Potential Yield ◽  
Gas Condensate Reservoirs ◽  
Point Pressure ◽  
Dew Point Pressure

The study of flooding gas condensate reservoirs at different stages of depletion (25, 50, 75% of the dew point pressure and at the maximum condensation pressure) with different potential hydrocarbon content of 100, 300 and 500 g/m3 and different voidage replacement by using injection (50, 100 and 150%). The results showed a positive effect of water injection on the increase of the condensate recovery factor, but a decrease in gas production compared to the basic options of development at depletion drive. Thus, for formation systems with medium and high potential yield of liquid hydrocarbons C5+, the largest incremental production is obtained in the case when water injection begins with minimum depletion of formation energy. While for a formation system with a low potential yield (100 g/m3) the maximum technological effect is obtained under the condition of maximum depletion. In the case of medium and high C5+ yield in the formation gas, with a slight decrease in the formation pressure by 25 or 50% of the dew point pressure, the maximum increase in the condensate recovery factor is achieved at high injection rates with 100 or 150% voidage replacement. The obtained results can be used for rapid screening of potential methods of impact on the gas condensate reservoir, and the final decision concerning the technological parameters of production and injection wells operation will be made due to the results of optimization of multivariate hydrodynamic calculations using geological and technological models.

scholarly journals Performance Evaluation of CO2 Huff-n-Puff Gas Injection in Shale Gas Condensate Reservoirs

Energies ◽  
2018 ◽  
Vol 12 (1) ◽  
pp. 42 ◽  
Author(s):  
Xingbang Meng ◽  
Zhan Meng ◽  
Jixiang Ma ◽  
Tengfei Wang
Keyword(s):  
Oil Recovery ◽  
Shale Gas ◽  
Injection Pressure ◽  
Gas Condensate ◽  
Dew Point ◽  
Gas Condensate Reservoirs ◽  
Gas Recovery ◽  
Point Pressure ◽  
Shale Reservoirs ◽  
Dew Point Pressure

When the reservoir pressure is decreased lower than the dew point pressure in shale gas condensate reservoirs, condensate would be formed in the formation. Condensate accumulation severely reduces the commercial production of shale gas condensate reservoirs. Seeking ways to mitigate condensate in the formation and enhance both condensate and gas recovery in shale reservoirs has important significance. Very few related studies have been done. In this paper, both experimental and numerical studies were conducted to evaluate the performance of CO2 huff-n-puff to enhance the condensate recovery in shale reservoirs. Experimentally, CO2 huff-n-puff tests on shale core were conducted. A theoretical field scale simulation model was constructed. The effects of injection pressure, injection time, and soaking time on the efficiency of CO2 huff-n-puff were examined. Experimental results indicate that condensate recovery was enhanced to 30.36% after 5 cycles of CO2 huff-n-puff. In addition, simulation results indicate that the injection period and injection pressure should be optimized to ensure that the pressure of the main condensate region remains higher than the dew point pressure. The soaking process should be determined based on the injection pressure. This work may shed light on a better understanding of the CO2 huff-n-puff- enhanced oil recovery (EOR) strategy in shale gas condensate reservoirs.

scholarly journals Investigating the Behavior of Low Permeable Lean and Rich Gas Condensate Reservoirs

2018 ◽  
Vol 8 (6) ◽  
Author(s):  
Sohail Nawab ◽  
Abdul Haque Tunio ◽  
Aftab Ahmed Mahesar ◽  
Imran Ahmed Hullio
Keyword(s):  
Gas Condensate ◽  
Dew Point ◽  
Reservoir Rock ◽  
New Paradigm ◽  
Gas Condensate Reservoirs ◽  
Gas Recovery ◽  
Condensate Reservoir ◽  
Compositional Simulator ◽  
Point Pressure ◽  
Dew Point Pressure

The producing behavior of low permeable gas condensate reservoirs is dramatically different from that of conventional reservoirs and requires a new paradigm to understand and interpret it. As the reservoir pressure initiates to decline and reaches to dew point pressure of the fluid then the condensate is formed and causes the restriction in the flow in the reservoir rock which results, decrease in the well productivity near the wellbore vicinity which is known as condensate blockage. Henceforward, it is better to understand the behavior of the low permeable lean and rich gas condensate reservoirs by several perspectives through the compositional simulator. Besides this study involves the following perspectives; the increase in the number of wells and by varying the flowrate of the gas in six different cases for low permeable lean and rich gas condensate reservoirs. It was concluded that low permeable lean and rich gas condensate reservoirs have similar gas recovery factors. Whereas the CRF plays inverse behavior for both reservoirs as CRF is maximum for lean gas condensate at single producing well but for rich gas condensate reservoir the CRF increases as the number of wells escalates. Additionally, in second effect the varying gas flowrates lean gas condensate reservoir has maximum CRF at lesser flowrate but it is opposite for the low permeable rich gas condensate reservoir, for single or two producing wells the flowrate effect plays but when the number of wells is increasing there is not any significant change in CRF

Case Study of Condensate Dropout Effect in Unconventional Gas/Condensate Reservoirs with Hydraulically Fractured Wells

2022 ◽  
Author(s):  
Ali H. Alsultan ◽  
Josef R. Shaoul ◽  
Jason Park ◽  
Pacelli L. J. Zitha
Keyword(s):  
Gas Production ◽  
Gas Condensate ◽  
Dew Point ◽  
Productivity Index ◽  
Large Reservoir ◽  
Unconventional Gas ◽  
Gas Condensate Reservoirs ◽  
Liquid Saturation ◽  
Reservoir Volume ◽  
Fracture Performance

Abstract Condensate banking is a major issue in the production operations of gas condensate reservoirs. Increase in liquid saturation in the near-wellbore zone due to pressure decline below dew point, decreases well deliverability and the produced condensate-gas ratio (CGR). This paper investigates the effects of condensate banking on the deliverability of hydraulically fractured wells producing from ultralow permeability (0.001 to 0.1 mD) gas condensate reservoirs. Cases where condensate dropout occurs over a large volume of the reservoir, not only near the fracture face, were examined by a detailed numerical reservoir simulation. A commercial compositional simulator with local grid refinement (LGR) around the fracture was used to quantify condensate dropout as a result of reservoir pressure decline and its impact on well productivity index (PI). The effects of gas production rate and reservoir permeability were investigated. Numerical simulation results showed a significant change in fluid compositions and relative permeability to gas over a large reservoir volume due to pressure decline during reservoir depletion. Results further illustrated the complications in understanding the PI evolution of hydraulically fractured wells in "unconventional" gas condensate reservoirs and illustrate how to correctly evaluate fracture performance in such a situation. The findings of our study and novel approach help to more accurately predict post-fracture performance. They provide a better understanding of the hydrocarbon phase change not only near the wellbore and fracture, but also deep in the reservoir, which is critical in unconventional gas condensate reservoirs. The optimization of both fracture spacing in horizontal wells and well spacing for vertical well developments can be achieved by improving the ability of production engineers to generate more realistic predictions of gas and condensate production over time.

Modeling Condensate Banking Mitigation by Enhanced Gas Recovery Methods

2021 ◽  
Author(s):  
Adel Mohsin ◽  
Abdul Salam Abd ◽  
Ahmad Abushaikha
Keyword(s):  
Natural Gas ◽  
Finite Difference ◽  
Positive Impact ◽  
Enhanced Recovery ◽  
Gas Production ◽  
Dew Point ◽  
Productivity Index ◽  
Base Case ◽  
Enhanced Gas Recovery ◽  
Gas Recovery

Abstract Condensate banking in natural gas reservoirs can hinder the productivity of production wells dramatically due to the multiphase flow behaviour around the wellbore. This phenomenon takes place when the reservoir pressure drops below the dew point pressure. In this work, we model this occurrence and investigate how the injection of CO2 can enhance the well productivity using novel discretization and linearization schemes such as mimetic finite difference and operator-based linearization from an in-house built compositional reservoir simulator. The injection of CO2 as an enhanced recovery technique is chosen to assess its value as a potential remedy to reduce carbon emissions associated with natural gas production. First, we model a base case with a single producer where we show the deposition of condensate banking around the well and the decline of pressure and production with time. In another case, we inject CO2 into the reservoir as an enhanced gas recovery mechanism. In both cases, we use fully tensor permeability and unstructured tetrahedral grids using mimetic finite difference (MFD) method. The results of the simulation show that the gas and condensate production rates drop after a certain production plateau, specifically the drop in the condensate rate by up to 46%. The introduction of a CO2 injector yields a positive impact on the productivity and pressure decline of the well, delaying the plateau by up to 1.5 years. It also improves the productivity index by above 35% on both the gas and condensate performance, thus reducing production rate loss on both gas and condensate by over 8% and the pressure, while in terms of pressure and drawdown, an improvement of 2.9 to 19.6% is observed per year.

Evaluation of Transport Properties Effect on the Performance of Gas-Condensate Reservoirs Using Compositional Simulation

2017 ◽  
Vol 139 (3) ◽  
Author(s):  
Bander N. Al Ghamdi ◽  
Luis F. Ayala H.
Keyword(s):  
Transport Properties ◽  
Relative Permeability ◽  
Gas Condensate ◽  
Compositional Simulation ◽  
Saturation Point ◽  
Flow Phenomenon ◽  
Gas Condensate Reservoirs ◽  
Compositional Simulator ◽  
Tight Formations ◽  
Relative Permeability Curves

Gas-condensate productivity is highly dependent on the thermodynamic behavior of the fluids-in-place. The condensation attendant with the depletion of gas-condensate reservoirs leads to a deficiency in the flow of fluids moving toward the production channels. The impairment is a result of condensate accumulation near the production channels in an immobility state until reaching a critical saturation point. Considering the flow phenomenon of gas-condensate reservoirs, tight formations can be inevitably complex hosting environments in which to achieve economical production. This work is aimed to assess the productivity gas-condensate reservoirs in a naturally fractured setting against the effect of capillary pressure and relative permeability constraints. The severity of condensate coating and magnitude of impairment was evaluated in a system with a permeability of 0.001 mD using an in-house compositional simulator. Several composition combinations were considered to portray mixtures ascending in complexity from light to heavy. The examination showed that thicker walls of condensate and greater impairment are attained with mixture containing higher nonvolatile concentrations. In addition, the influence of different capillary curves was insignificant to the overall behavior of fluids-in-place and movement within the pores medium. A greater impact on the transport of fluids was owed to relative permeability curves, which showed dependency on the extent of condensate content. Activating diffusion was found to diminish flow constraints due to the capturing of additional extractions that were not accounted for under Darcy's law alone.

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