Measurement and Correlation of Gas Condensate Relative Permeability by the Steady-State Method

1998 ◽  
Vol 1 (02) ◽  
pp. 134-140 ◽  
Author(s):  
G.D. Henderson ◽  
A. Danesh ◽  
D.H. Tehrani ◽  
S. Al-Shaidi ◽  
J.M. Peden
Keyword(s):  
Steady State ◽  
Relative Permeability ◽  
Flow Rate ◽  
Rate Effect ◽  
Gas Condensate ◽  
Dew Point ◽  
Gas Condensate Reservoirs ◽  
Steady State Method ◽  
Wide Range ◽  
Permeability Rate

Abstract High pressure core flood experiments using gas condensate fluids in long sandstone cores have been conducted. Steady-state relative permeability points were measured over a wide range of condensate to gas ratio's (CGR), with the velocity and interfacial tension (IFT) being varied between tests in order to observe the effect on relative permeability. The experimental procedures ensured that the fluid distribution in the cores was representative of gas condensate reservoirs. Hysteresis between drainage and imbibition during the steady-state measurements was also investigated, as was the repeatability of the data. A relative permeability rate effect for both gas and condensate phases was observed, with the relative permeability of both phases increasing with an increase in flow rate. The relative permeability rate effect was still evident as the IFT increased by an order of magnitude, with the relative permeability of the gas phase reducing more than the condensate phase. The influence of end effects was shown to be negligible at the IFT conditions used in the tests, with the Reynolds number indicating that flow was well within the so called laminar regime at all test conditions. The observed rate effect was contrary to that of the conventional non-Darcy flow where the effective permeability should decrease with increasing flow rate. A generalised correlation between relative permeability, velocity and IFT has been proposed, which should be more appropriate for condensing fluids than the conventional correlation. The results highlight the need for appropriate experimental methods and relative permeability relations where the distribution of the phases are representative of those in gas condensate reservoirs. This study will be particularly applicable to the vicinity of producing wells, where the rate effect on gas relative permeability can significantly affect well productivity. The findings provide previously unreported data on relative permeability and recovery of gas condensate fluids at realistic conditions. Introduction During the production of gas condensate reservoirs, the reservoir pressure will be gradually reduced to below the dew-point, giving rise to retrograde condensation. In the vicinity of producing wells where the rate of pressure reduction is greatest, the increase in the condensate saturation from zero is accompanied by a reduction in relative permeability of gas, due to the loss of pore space available to gas flow. It is the perceived effect of this local condensate accumulation on the near wellbore gas and condensate mobility that is one of the main areas of interest for reservoir engineers. The availability of accurate relative permeability data applicable to flow in the wellbore region impacts the management of gas condensate reservoirs.

Work With Chemical Additives Advances Understanding of Relative Permeability Shifts

2021 ◽  
Vol 73 (09) ◽  
pp. 37-38
Author(s):  
Chris Carpenter
Keyword(s):  
Steady State ◽  
Relative Permeability ◽  
Flow Rate ◽  
Pressure Difference ◽  
Effective Permeability ◽  
Constant Flow ◽  
Chemical Additives ◽  
Flow Rates ◽  
Steady State Method ◽  
Tight Rocks

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201520, “Advances in Understanding Relative Permeability Shifts by Imbibition of Surfactant Solutions Into Tight Plugs,” by Mohammad Yousefi, Lin Yuan, and Hassan Dehghanpour, SPE, University of Alberta, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Various chemical additives have been proposed recently to enhance imbibition oil recovery from tight formations during shut-in periods after hydraulic fracturing operations. In the complete paper, the authors develop and apply a laboratory protocol mimicking leakoff, shut-in, and flowback processes to evaluate the effects of fracturing-fluid additives on oil regained permeability. A conventional coreflooding apparatus is modified to measure oil effective permeability (koeff) before and after the surfactant-imbibition experiments. Methodology Proposed Technique for Measuring Oil Effective Permeability. Despite the simplicity of the steady-state method, measuring permeability of tight rocks with this technique is challenging because of its time-consuming nature and the fact that accurate measurement is necessary of extremely low flow rates corresponding to low injectivity of tight rocks. The authors use a pair of plugs from a well drilled in the Montney formation that is a stratigraphic unit of the Lower Triassic age in the western Canadian sedimentary basin located in British Columbia and Alberta. It is mainly a low-permeability siltstone reservoir. In the modified coreflooding apparatus, the authors reduce the effect of compressibility in order to reduce the duration of the transient period by approximately one order of magnitude. Because monitoring changes in pressure is much easier and more accurate than monitoring flow-rate changes, a constant flow-rate mode is used and pressure is recorded with time. Oil is injected at different constant flow rates (qo), and the inlet pressure is monitored. The stable pressure difference across the plug is recorded for each flow rate. After steady-state conditions are reached based on the pressure profile, the qo is increased. This process is repeated until four stable pressure differences corresponding to four different qo are obtained. After the highest qo is reached, it is decreased in similar steps to check the repeatability of each data point. The permeability is calculated with the Darcy equation and slope of the qo vs. stable pressure difference across the plug.

Application of X-ray Scanner in Measurement of Gas Condensate Relative Permeability Using Steady-State Method

2007 ◽  
Vol 25 (8) ◽  
pp. 1081-1097
Author(s):  
H. S. Al-Hashim ◽  
H. Y. Al-Yousef ◽  
A. Arshad ◽  
S. Z. Jilani ◽  
S. -ur-Rahman ◽  
...  
Keyword(s):  
Steady State ◽  
Relative Permeability ◽  
Gas Condensate ◽  
X Ray ◽  
Steady State Method ◽  
State Method

Measurement and Correlation of Gas Condensate Relative Permeability by the Steady-State Method

SPE Journal ◽  
1996 ◽  
Vol 1 (02) ◽  
pp. 191-202 ◽  
Author(s):  
G.D. Henderson ◽  
A. Danesh ◽  
D.H. Tehrani ◽  
S. Al-Shaidi ◽  
J.M. Peden
Keyword(s):  
Steady State ◽  
Relative Permeability ◽  
Gas Condensate ◽  
Steady State Method ◽  
State Method

scholarly journals Determination of Permeability and Inertial Coefficients of Sintered Metal Porous Media Using an Isothermal Chamber

2018 ◽  
Vol 8 (9) ◽  
pp. 1670 ◽  
Author(s):  
Wei Zhong ◽  
Xiang Ji ◽  
Chong Li ◽  
Jiwen Fang ◽  
Fanghua Liu
Keyword(s):  
Porous Media ◽  
Steady State ◽  
Flow Rate ◽  
Pressure Difference ◽  
Testing Time ◽  
Sintered Metal ◽  
Steady State Method ◽  
Volume Limit ◽  
Inertial Coefficient

Sintered metal porous media are widely used in a broad range of industrial equipment. Generally, the flow properties in porous media are represented by an incompressible Darcy‒Forchheimer regime. This study uses a modified Forchheimer equation to represent the flow rate characteristics, which are then experimentally and theoretically investigated using a few samples of sintered metal porous media. The traditional steady-state method has a long testing time and considerable air consumption. With this in mind, a discharge method based on an isothermal chamber filled with copper wires is proposed to simultaneously determine the permeability and inertial coefficient. The flow rate discharged from the isothermal chamber is calculated by differentiating the measured pressure, and a paired dataset of pressure difference and flow rate is available. The theoretical representations of pressure difference versus flow rate show good agreement with the steady-state results. Finally, the volume limit of the isothermal chamber is addressed to ensure sufficient accuracy.

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.

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 .

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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