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

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.

Distribution of the Initial Fluid Composition in an Oil-Gas-Condensate Reservoir with Incomplete Gravity Segregation

It is known that initial composition of the hydrocarbon fluid in a petroleum reservoir changes significantly with depth due to the influence of gravity and geothermal gradient. Classical models of these phenomena are based on the assumption of equilibrium (quasiequilibrium) distribution of component concentrations in the gravity field with the presence of stationary thermodiffusional flux. However, there are typical situations in gas condensate reservoirs when the quasi-equilibrium conditions are not met. For example, this is true if immobile residual oil exists in the reservoir or for deep tight formations where gravity segregation is not completed. For such cases, modified models are required. They are proposed in this paper to take into account the non-equilibrium conditions of the initial fluid composition distribution in gas condensate (or oil-gas-condensate) reservoirs.

Theoretical and Methodological Features for Gas-condensate PVT Fluid Modelling with Limited Data

Majority of gas-condensate reservoir discoveries in Dnieper-Donets Basin (Ukraine), is characterized by limited composition only up to C5+, phase behavior studied by non-equilibrium, so called differential condensation PVT experiment, combined with the uncertainty in condensate production allocation to individual wells, makes the direct application of the results in modern PVT modeling software not possible. The new method, based on the Engler distillation test (ASTM86) for definition of pseudo-components combined with synthetic creation of liquid saturation curve for CVD experiment, was proposed and successfully applied for different gas-condensate reservoirs in the area of study. The quality control (QC) of the PVT model is further performed by applying material-balance method on a single-cell simulation model for exported black-oil PVT formulation when needed. The method proved being useful for modeling of multiple gas-condensate reservoirs of Dnieper-Donets Basin with different potential condensate yields varying from 30 to 700 g/m3 and as an example presented for two reservoir fluids with 108 and 536 g/m3. Results of numerical simulation studies were within the engineering accuracy in comparison to historically observed values. The investigation showed that a representative fluid model can be create in the cases when no detailed fluid composition or required laboratory experiments are available. PVT model can be efficiently validated and QC-ed by performing material-balance type numeric simulation constructed with one cell. However, the proper fluid sampling and PVT cell laboratory experiments are still major requirements for precise reservoir fluid characterization and equation of state (EOS) modeling.

wells of gas and gas condensate reservoirs in the South-Eastern part of the Bukhara-Khiva region and methods for increasing their productivity

The article examines the methods of increasing the productivity of wells of gas and gas condensate reservoirs in the south-eastern part of the Bukhara-Khiva region (BHR). The role of gas calculation methods in determining the gas reserve of Mesopotamia in sveza with an increase in the share of gas reserves from 1 to 10 million tons of conventional fuel is shown. Certain difficulties have been identified in the issue of reliable determination of gas reserves in the limited fund of wells and large ranges of changes in calculated parameters. The determining significance of the value of gas reserves in calculating the forecast indicators of the development and technologies of their extraction is justified. It is established that increasing the degree of reliability of calculating gas reserves ensures the efficiency of its extraction, as well as the rational use of material and technical resources and financial capabilities of the enterprise. The advantages of such methods for determining gas reserves as the volume method, the material balance method, and static models are disclosed. A specific description of each of these methods and their application for calculating gas reserves at the Northern Guzar field is given.

Monitoring the composition of gas condensate well streams based on samples taken from multiphase flow meters

The article highlights the relevance of reliable estimation of the composition and properties of reservoir gas during the development of gas condensate fields and the complexity of the task for reservoirs containing zones of varying condensate content. The authors have developed a methodology that allows monitoring the composition of gas condensate well streams of similar reservoirs. There are successful examples of the approach applied in Achimov gas condensate reservoirs at the Urengoy oil and gas condensate field. The proposed approach is based on the use of the so-called fluid factors, which are calculated on the basis of the known component compositions of various flows of the studied hydrocarbon system. The correlation between certain "fluid factors" and the properties of reservoir gas (usually determined by more labor-consuming methods) allows one to quickly obtain important information necessary to solve various development control tasks.

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

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.

Carbon-Negative Scenarios in High CO2 Gas Condensate Reservoirs

A gas condensate reservoir in Northern Croatia was used as an example of a CO2 injection site during natural gas production to test whether the entire process is carbon-negative. To confirm this hypothesis, all three elements of the CO2 life cycle were included: (1) CO2 emitted by combustion of the produced gas from the start of production from the respective field, (2) CO2 that is separated at natural gas processing plant, i.e., the CO2 that was present in the original reservoir gas composition, and (3) the injected CO2 volumes. The selected reservoir is typical of gas-condensate reservoirs in Northern Croatia (and more generally in Drava Basin), as it contains about 50% CO2 (mole). Reservoir simulations of history-matched model showed base case (production without injection) and several cases of CO2 enhanced gas recovery, but with a focus on CO2 storage rather than maximizing hydrocarbon gas production achieved by converting a production well to a CO2 injection well. General findings are that even in gas reservoirs with such extreme initial CO2 content, gas production with CO2 injection can be carbon-negative. In almost all simulated CO2 injection scenarios, the process is carbon-negative from the time of CO2 injection, and in scenarios where CO2 injection begins earlier, it is carbon-negative from the start of gas production, which opens up the possibility of cost-effective storage of CO2 while producing natural gas with net negative CO2 emissions.

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

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.