Effect of Non-Darcy Flow on Well Productivity of a Hydraulically Fractured Gas-Condensate Well

2009 ◽  
Vol 12 (04) ◽  
pp. 576-585 ◽  
Author(s):  
Jitendra Mohan ◽  
Gary A. Pope ◽  
Mukul M. Sharma
Keyword(s):  
Hydraulic Fracturing ◽  
Relative Permeability ◽  
Gas Condensate ◽  
Darcy Flow ◽  
Productivity Improvement ◽  
Well Productivity ◽  
Fracture Width ◽  
Gas Condensate Reservoirs ◽  
The Impact ◽  
Actual Fracture

Summary Hydraulic fracturing is a common way to improve productivity of gas-condensate wells. Previous simulation studies have predicted much larger increases in well productivity than have been actually observed in the field. This paper shows the large impact of non-Darcy flow and condensate accumulation on the productivity of a hydraulically fractured gas-condensate well. Two-level local-grid refinement was used so that very small gridblocks corresponding to actual fracture width could be simulated. The actual fracture width must be used to accurately model non-Darcy flow. An unrealistically large fracture width in the simulations underestimates the effect of non-Darcy flow in hydraulic fractures. Various other factors governing the productivity improvement such as fracture length, fracture conductivity, well flow rates, and reservoir parameters have been analyzed. Productivity improvements were found to be overestimated by a factor as high as three, if non-Darcy flow was neglected. Results are presented that show the impact of condensate buildup on long-term productivity of wells in both rich and lean gas-condensate reservoirs. Introduction A significant decline in productivity of gas-condensate wells has been observed, resulting from a phenomenon called condensate blocking. Pressure gradients caused by fluid flow in the reservoir are greatest near the production well. As the pressure drops below the dewpoint pressure, liquid drops out and condensate accumulates near the well. This buildup of condensate is referred to as a condensate bank. The condensate continues to accumulate until a steady-state two-phase flow of condensate and gas is achieved. This condensate buildup decreases the relative permeability to gas, thereby causing a decline in the well productivity. Afidick et al. (1994) studied the Arun field in Indonesia, which is one of the largest gas-condensate reservoirs in the world. They concluded that a significant loss in productivity of the reservoir after 10 years of production was caused by condensate blockage. They found that condensate accumulation caused well productivity to decline by approximately 50%, even for this very lean gas. Boom et al. (1996) showed that even for a lean gas (e.g., less than 1% liquid dropout) a relatively high liquid saturation can build up in the near-wellbore region. Liquid saturations near the well can reach 50 to 60% under pseudosteady-state flow of gas and condensate (Cable et al. 2000; Henderson et al. 1998). Hydraulic fracturing of wells is a common practice to improve productivity of gas-condensate reservoirs. Modeling of gas-condensate wells with a hydraulic fracture requires taking into account non-Darcy flow. Gas velocity inside the fracture is three to four orders of magnitude higher than that in the matrix. Use of Darcy's law to model this flow can overestimate the productivity improvement. Therefore, it is necessary to use Forchheimer's equation to model this flow with an appropriate non-Darcy coefficient that takes into account the gas-relative permeability and water saturation.

Measurements of Relative Permeabilities for Calculating Gas-Condensate Well Deliverability

2000 ◽  
Vol 3 (06) ◽  
pp. 473-479 ◽  
Author(s):  
R.E. Mott ◽  
A.S. Cable ◽  
M.C. Spearing
Keyword(s):  
Relative Permeability ◽  
Capillary Number ◽  
Gas Condensate ◽  
Relative Permeabilities ◽  
Well Productivity ◽  
Gas Condensate Reservoirs ◽  
Liquid Saturation ◽  
Condensate Reservoir ◽  
Deep Reservoir ◽  
The Relationship

Summary Well deliverability in many gas-condensate reservoirs is reduced by condensate banking when the bottomhole pressure falls below the dewpoint, although the impact of condensate banking may be reduced due to improved mobility at high capillary number in the near-well region. This paper presents the results of relative permeability measurements on a sandstone core from a North Sea gas-condensate reservoir, at velocities that are typical of the near-well region. The results show a clear increase in mobility with capillary number, and the paper describes how the data can be modeled with empirical correlations which can be used in reservoir simulators. Introduction Well deliverability is an important issue in the development of many gas-condensate reservoirs, especially where permeability is low. When the well bottomhole flowing pressure falls below the dewpoint, condensate liquid may build up around the wellbore, causing a reduction in gas permeability and well productivity. In extreme cases the liquid saturation may reach values as high as 50 or 60% and the well deliverability may be reduced by up to an order of magnitude. The loss in productivity due to this "condensate banking" effect may be significant, even in very lean gas-condensate reservoirs. For example, in the Arun reservoir,1 the productivity reduced by a factor of about 2 as the pressure fell below the dewpoint, even though the reservoir fluid was very lean with a maximum liquid drop out of only 1% away from the well. Most of the pressure drop from condensate blockage occurs within a few feet of the wellbore, where velocities are very high. There is a growing body of evidence from laboratory coreflood experiments to suggest that gas-condensate relative permeabilities increase at high velocities, and that these changes can be correlated against the capillary number.2–8 The capillary number is a dimensionless number that measures the relative strength of viscous and capillary forces. There are several gas-condensate fields where simulation with conventional relative permeability models has been found to underestimate well productivity.1,9,10 To obtain a good match between simulation results and well-test data, it was necessary to increase the mobility in the near-well region, either empirically or through a model of the increase in relative permeability at high velocity. This effect can increase well productivity significantly, and in some cases may eliminate most of the effect of condensate blockage. Experimental Data Requirements Fevang and Whitson11 have shown that the key parameter in determining well deliverability is the relationship between krg and the ratio krg/ kro. When high-velocity effects are significant, the most important information is the variation of krg with krg/k ro and the capillary number Nc. The relevant values of krg/kro are determined by the pressure/volume/temperature (PVT) properties of the reservoir fluids, but typical values might be 10 to 100 for lean condensates, 1 to 10 for rich condensates, and 0.1 to 10 for near-critical fluids. There are various ways of defining the capillary number, but in this paper we use the definition (1)Nc=vgμgσ, so that the capillary number is proportional to the gas velocity and inversely proportional to interfacial tension (IFT). The capillary numbers that are relevant for well deliverability depend on the flow rate, fluid type, and well bottomhole pressure, but as a general rule, values between 10?6 and 10?3 are most important. Experimental Methods In a gas-condensate reservoir, there are important differences between the flow regimes in the regions close to and far from the well. These different flow regimes are reflected in the requirements for relative permeability data for the deep reservoir and near-well regions. Far from the well, velocities are low, and liquid mobility is usually less important, except in reservoirs containing very rich fluids. In the near-well region, both liquid and gas phases are mobile, velocities are high, and the liquid mobility is important because of its effect on the relationship between krg and krg/kro. Depletion Method. Relative permeabilities for the deep reservoir region are often measured in a coreflood experiment, where the fluids in the core are obtained by a constant volume depletion (CVD) on a reservoir fluid sample. Relative permeabilities are measured at decreasing pressures from the fluid dewpoint, and increasing liquid saturation. In this type of experiment, the liquid saturation cannot exceed the critical condensate saturation or the maximum value in a CVD experiment, so that it is not possible to acquire data at the high liquid saturations that occur in the reservoir near to the well. The "depletion" experiment provides relative permeability data that are relevant to the deep reservoir, but there can be problems in interpreting the results due to the effects of IFT. Changes in liquid saturation are achieved by reducing pressure, which results in a change of IFT. The increase in IFT as pressure falls may cause a large reduction in mobility, and Chen et al.12 describe an example where the condensate liquid relative permeability decreases with increasing liquid saturation. Steady-State Method. The steady-state technique can be used to measure relative permeabilities at the higher liquid saturations that occur in the near-well region. Liquid and gas can be injected into the core from separate vessels, allowing relative permeabilities to be measured for a wide range of saturations. Results of gas-condensate relative permeabilities measured by this technique have been reported by Henderson et al.2,6 and Chen et al.12 .

scholarly journals Hydraulic Fracturing Designs For Low Permeability Gas Condensate Reservoirs Having Lean and Rich Condensate Compositions

2017 ◽  
Vol 3 (3) ◽  
pp. 9
Author(s):  
Karanthakarn Mekmok ◽  
Jirawat Chewaroungroaj
Keyword(s):  
Hydraulic Fracturing ◽  
Gas Condensate ◽  
Dew Point ◽  
Well Productivity ◽  
Fracture Conductivity ◽  
Gas Condensate Reservoirs ◽  
Point Pressure ◽  
Condensate Blockage ◽  
Dew Point Pressure ◽  
Saturation Profile

Gas condensate reservoirs have been challenging many researchers in petroleum industry for decades because of their complexities in flow behavior. After dew point pressure is reached, gas condensate will drop liquid out and increase liquid saturation near wellbore vicinity called condensate banking or condensate blockage. Hydraulic fracturing in horizontal direction has been proved to be a reliable method to mitigate condensate blockage and increase productivity of gas condensate well by means of pressure redistribution in the near wellbore vicinity. In this paper the parameters of dimensionless fracture conductivity and Stimulated Reservoir Volume (SRV) designs of lean and rich condensate compositions are studied. Well productivity and saturation profile of each design had been observed. The results from this study indicate that the higher dimensionless fracture conductivity gives the higher well productivity in every studied parameter in lean condensate composition. However, in rich condensate composition shows different trend of results because it has higher heavy ends (C7+) that drop into liquid easier once pressure falls below dew point pressure. The maximum number of fracture and fracture permeability can be recognized in the study of rich condensate. In the study of SRV indicates that number of fracture is superior to fracture width in both gas and condensate productivity. Moreover, performing hydraulic fracturing can decrease pressure drawdown, production time and liquid dropout which leads to the mitigation of condensate banking near wellbore that can be recognized in the study of condensate saturation profile.

The impact of pertinent parameters on the design of hydraulic fracturing in gas condensate reservoirs

2005 ◽  
Author(s):  
Gustavo Adolfo Carvajal ◽  
Ali Danesh ◽  
Mahmoud Jamiolahmady ◽  
Mehran Sohrabi
Keyword(s):  
Hydraulic Fracturing ◽  
Gas Condensate ◽  
Gas Condensate Reservoirs ◽  
The Impact

Estimating Productivity-Controlling Parameters in Gas/Condensate Wells From Transient Pressure Data

2007 ◽  
Vol 10 (02) ◽  
pp. 100-111 ◽  
Author(s):  
Manijeh Bozorgzadeh ◽  
Alain C. Gringarten
Keyword(s):  
Relative Permeability ◽  
Capillary Number ◽  
Gas Condensate ◽  
Absolute Permeability ◽  
Well Test ◽  
Well Test Analysis ◽  
Two Phase ◽  
Well Productivity ◽  
Gas Condensate Reservoirs ◽  
Relative Permeability Curves

Summary The ability to predict well deliverability is a key issue for the development of gas/condensate reservoirs. We show in this paper that well deliverability depends mainly on the gas relative permeabilities at both the endpoint and the near-wellbore saturations, as well as on the reservoir permeability. We then demonstrate how these parameters and the base capillary number can be obtained from pressure-buildup data by using single-phase and two-phase pseudopressures simultaneously. These parameters can in turn be used to estimate gas relative permeability curves. Finally, we illustrate this approach with both simulated pressure-buildup data and an actual field case. Introduction and Background In gas/condensate reservoirs, a condensate bank forms around the wellbore when the bottomhole pressure (BHP) falls below the dewpoint pressure. This creates three different saturation zones around the well. Close to the wellbore, high condensate saturation reduces the effective permeability to gas, resulting in severe well productivity decline (Kniazeff and Nvaille 1965; Afidick et al. 1994; Lee and Chaverra 1998; Jutila et al. 2001; Briones et al. 2002). This decline is reduced at high gas rates and/or low capillary forces, which lower condensate saturation in the immediate vicinity of the wellbore, resulting in a corresponding increase in the gas relative permeability. This is called the capillary-number effect, positive coupling, viscous stripping, or velocity stripping (Boom et al. 1995; Henderson et al. 1998, 2000a; Ali et al. 1997a; Blom et al. 1997). High gas rates, on the other hand, induce inertia (also referred to as turbulent or non-Darcy flow effects), which reduces productivity. Well productivity is thus a balance between capillary number and inertia effects (Boom et al. 1995; Henderson et al. 1998, 2000a; Ali et al. 1997a, 1997b; Blom et al. 1997; Mott et al. 2000.). Well-deliverability forecasts for gas/condensate wells are usually performed with the help of numerical compositional simulators. Compositional simulation requires fine gridding to model the formation of the condensate bank with the required accuracy (Ali et al. 1997a). Non-Darcy flow and capillary-number effects (Mott 2003) are accounted for through empirical correlations, which require inputs such as the base capillary number (i.e., the minimum value required to see capillary-number effects), the reservoir absolute permeability, and the relative permeability curves. These are usually determined experimentally, but laboratory measurements at near-wellbore conditions are very difficult and expensive to obtain. An alternative, as shown in this paper, is to obtain them from well-test data. Well-test analysis is recognized as a valuable tool for reservoir surveillance and monitoring and provides estimates of a number of parameters required for reservoir characterization, reservoir simulation, and well-productivity forecasting. In gas/condensate reservoirs, when the BHP is below the dewpoint pressure, the effective permeability to gas in the near-wellbore region and at initial liquid saturation can be estimated with single-phase pseudopressures (Al-Hussainy et al. 1966) and a two- or three-region radial composite well-test-interpretation model (Chu and Shank 1993; Gringarten et al. 2000; Daungkaew et al. 2002), whereas the reservoir absolute permeability may be determined with two-phase steady-state pseudopressures (Raghavan et al. 1999; Xu and Lee 1999). In this paper, we show that well-test analysis can provide additional parameters, such as the gas relative permeabilities at both the endpoint and the near-wellbore saturations and the base capillary number. These in turn can be used to generate estimated relative permeability curves for gas.

scholarly journals A new and simple model for the prediction of horizontal well productivity in gas condensate reservoirs

Fuel ◽  
2018 ◽  
Vol 223 ◽  
pp. 431-450 ◽  
Author(s):  
Panteha Ghahri ◽  
Mahmoud Jamiolahmadi ◽  
Ebrahim Alatefi ◽  
David Wilkinson ◽  
Farzaneh Sedighi Dehkordi ◽  
...  
Keyword(s):  
Simple Model ◽  
Horizontal Well ◽  
Gas Condensate ◽  
Well Productivity ◽  
Gas Condensate Reservoirs

Advanced Well Completion Strategies to Improve Gas Production Deliverability in Marginal Tight Gas Reservoirs from an Onshore Abu Dhabi Gas Field

2021 ◽  
Author(s):  
Hajar Ali Abdulla Al Shehhi ◽  
Bondan Bernadi ◽  
Alia Belal Zuwaid Belal Al Shamsi ◽  
Shamma Jasem Al Hammadi ◽  
Fatima Omar Alawadhi ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Wells ◽  
Gas Production ◽  
Abu Dhabi ◽  
Tight Gas ◽  
Production Rates ◽  
Well Productivity ◽  
Gas Saturation ◽  
Well Design ◽  
The Impact

Abstract Reservoir X is a marginal tight gas condensate reservoir located in Abu Dhabi with permeability of less than 0.05 mD. The field was conventionally developed with a few single horizontal wells, though sharp production decline was observed due to rapid pressure depletion. This study investigates the impact of converting the existing single horizontal wells into single long horizontal, dual laterals, triple laterals, fishbone design and hydraulic fracturing in improving well productivity. The existing wells design modifications were planned using a near reservoir simulator. The study evaluated the impact of length, trajectory, number of laterals and perforation intervals. For Single, dual, and triple lateral wells, additional simulation study with hydraulic fracturing was carried out. To evaluate and obtain effective comparisons, sector models with LGR was built to improve the simulation accuracy in areas near the wellbore. The study conducted a detailed investigation into the impact of various well designs on the well productivity. It was observed that maximizing the reservoir contact and targeting areas with high gas saturation led to significant increase in the well productivity. The simulation results revealed that longer laterals led to higher gas production rates. Dual lateral wells showed improved productivity when compared to single lateral wells. This incremental gain in the production was attributed to increased contact with the reservoir. The triple lateral well design yielded higher productivity compared to single and dual lateral wells. Hydraulic fracturing for single, dual, and triple lateral wells showed significant improvement in the gas production rates and reduced condensate banking near the wellbore. A detailed investigation into the fishbone design was carried out, this involved running sensitivity runs by varying the number of branches. Fishbone design showed considerable increment in production when compared to other well designs This paper demonstrates that increasing the reservoir contact and targeting specific areas of the reservoir with high gas saturation can lead to significant increase in the well productivity. The study also reveals that having longer and multiple laterals in the well leads to higher production rates. Hydraulic fracturing led to higher production gains. Fishbone well design with its multiple branches showed the most production again when compared to other well designs.

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