Mofazzal Hossain

Fluid flow through porous media using distinct element based numerical method

Many analytical and numerical methods have been developed to describe and analyse fluid flow through the reservoir’s porous media. The medium considered by most of these models is continuum based homogeneous media. But if the formation is not homogenous or if there is some discontinuity in the formation, most of these models become very complex and their solutions lose their accuracy, especially when the shape or reservoir geometry and boundary conditions are complex. In this paper, distinct element method (DEM) is used to simulate fluid flow in porous media. The DEM method is independent of the initial and boundary conditions, as well as reservoir geometry and discontinuity. The DEM based model proposed in this study is appeared to be unique in nature with capability to be used for any reservoir with higher degrees of complexity associated with the shape and geometry of its porous media, conditions of fluid flow, as well as initial and boundary conditions. This model has first been developed by Itasca Consulting Company and is further improved in this paper. Since the release of the model by Itasca, it has not been validated for fluid flow application in porous media, especially in case of petroleum reservoir. In this paper, two scenarios of linear and radial fluid flow in a finite reservoir are considered. Analytical models for these two cases are developed to set a benchmark for the comparison of simulation data. It is demonstrated that the simulation results are in good agreement with analytical results. Another major improvement in the model is using the servo controlled walls instead of particles to introduce tectonic stresses on the formation to simulate more realistic situations. The proposed model is then used to analyse fluid flow and pressure behaviour for hydraulically induced fractured and naturally fractured reservoir to justify the potential application of the model.

Characterizing natural fractures productivity in tight gas reservoirs

Tight formations normally have production problems mainly due to very low matrix permeability and various forms of formation damage that occur during drilling completion and production operation. In naturally fractured tight gas reservoirs, gas is mainly stored in the rock matrix with very low permeability, and the natural fractures have the main contribution on total gas production. Therefore, identifying natural fractures characteristics in the tight formations is essential for well productivity evaluations. Well testing and logging are the common tools employed to evaluate well productivity. Use of image log can provide fracture static parameters, and welltest analysis can provide data related to reservoir dynamic parameters. However, due to the low matrix permeability and complexity of the formation in naturally fractured tight gas reservoirs, welltest data are affected by long wellbore storage effect that masks the reservoir response to pressure change, and it may fail to provide dual-porosity dual-permeability models dynamic characteristics such as fracture permeability, fracture storativity ratio and interporosity flow coefficient. Therefore, application of welltest and image log data in naturally fractured tight gas reservoirs for meaningful results may not be well understood and the data may be difficult to interpret. This paper presents the estimation of fracture permeability in naturally fractured tight gas formations, by integration of welltest analysis results and image log data based on Kazemi’s simplified model. Reservoir simulation of dual-porosity and dual-permeability systems and sensitivity analysis are performed for different matrix and fracture parameters to understand the relationship between natural fractures parameters with welltest permeability. The simulation results confirmed reliability of the proposed correlation for fracture permeability estimation. A field example is also shown to demonstrate application of welltest analysis and image log data processing results in estimating average permeability of natural fractures for the tight gas reservoir.

Potential Application of Downhole Gas Compressor to Improve Productivity for Gas Reservoir

Downhole Gas Compression (DGC) is the new form of Artificial Lift Technology used to increase the productivity of gas wells. Surface compressors are commonly used to reduce the pressure at the wellhead, which in turn reduces flowing bottom hole pressure, and boost the well productivity for a gas well especially during its decline phase when average reservoir pressure falls to a value equal to the pressure in the wellbore imposed by the sales line at the surface, plus the pressure losses that occur in the gathering system and the tubing. This conventional technique is not very efficient for the gas wells that produce significant amount of liquid (water or condensate), since this liquid needs to be separated before reaching the gas compressor. In addition, it also requires additional space for compressor assembly into the well, which may be very challenging for wells in offshore and subsea environment. As an alternative to surface compressors, downhole gas compressors technique can be applied to increase the well productivity, especially gas wells in offshore and subsea environment. Some study claimed that this new technology could: increase more than 30% of gas production; resolve many multiphase related issues; and delay the onset of liquid loading. However, numerous challenges associated with design, development and implementation of this new technology are not well understood or documented.

A new practical approach to evaluate near wellbore formation damage parameter based on well test analysis for gas reservoir

Prediction of degree of near-wellbore damaged caused during drilling and completion is extremely difficult and challenging in any reservoir development program. It plays a vital role on decision making, specifically when the decision has to be made based on inflow performance relationship (IPR) analysis. Skin factor used for most of the IPR models are either calculated from analytical models depending on the near wellbore conditions (e.g. open hole, perforated, gravel packing etc.); or predicted based on expensive well test data. While accuracy of the predicted results depends on the accuracy of input parameters available to feed into model, nevertheless this approach can generate range of uncertainties with misleading predicted results that significant effect on decision making. This paper presents a simplified practical method of estimating the extent of damage and amount of skin in a reservoir. Correlations for the permeability in the damage zone have been developed as a function of the average reservoir permeability in the drainage area of reservoirs for steady, stabilized or transient flow conditions. The model uses well deliverability test data to predict average permeability in the drainage zone. The model has been applied to different cases using representative field test data for high and low permeable reservoirs. It has been demonstrated that the proposed model exhibits very good approximation of damage components affecting reservoirs. From this analysis, it could also be concluded that by using data from unsteady flow deliverability tests, it is possible to get a good estimation of the damage skin in a reservoir and its extent. This is valid as long as the damage does not exceed the transient drainage radius. Exceeding the transient drainage radius will imply deriving very large skin values from the test, and this is rare in most cases.

A New Practical Approach To Evaluate Near Wellbore Formation Damage Parameters Based on Well Test Analysis for Gas Reservoir

Prediction of degree of near-wellbore damaged caused during drilling and completion is extremely difficult and challenging in any reservoir development program. It plays a vital role on decision making, specifically when the decision has to be made based on inflow performance relationship (IPR) analysis. Skin factor used for most of the IPR models are either calculated from analytical models depending on the near wellbore conditions (e.g. open hole, perforated, gravel packing etc.); or predicted based on expensive well test data. While accuracy of the predicted results depends on the accuracy of input parameters available to feed into model, nevertheless this approach can generate range of uncertainties with misleading predicted results that significant effect on decision making. This paper presents a simplified practical method of estimating the extent of damage and amount of skin in a reservoir. Correlations for the permeability in the damage zone have been developed as a function of the average reservoir permeability in the drainage area of reservoirs for steady, stabilized or transient flow conditions. The model uses well deliverability test data to predict average permeability in the drainage zone. The model has been applied to different cases using representative field test data for high and low permeable reservoirs. It has been demonstrated that the proposed model exhibits very good approximation of damage components affecting reservoirs. From this analysis, it could also be concluded that by using data from unsteady flow deliverability tests, it is possible to get a good estimation of the damage skin in a reservoir and its extent. This is valid as long as the damage does not exceed the transient drainage radius. Exceeding the transient drainage radius will imply deriving very large skin values from the test, and this is rare in most cases.

Effect of Sand Lens Size and Hydraulic Fractures Parameters on Gas In Place Estimation Using

Low permeability and complexities of rock formation in tight gas reservoirs make it more complicated to predict well production performance and estimate gas recovery. To produce from the unconventional reservoirs in the case that formation rock is not sensitive to damage caused by liquid invasion, hydraulic fracturing is the most common stimulation treatment to improve the production to the excepted economically rate. In term of reservoir geometry, tight sand formations are normally consisted by the stacks of isolated lenses of sand bodies that are separated by impermeable layers (e.g. shale). Each sand lens varies in shape and size and acts as a trap for original hydrocarbon accumulations. The sand lenses parameters such as length and width can play important role in controlling gas recovery from hydraulically fractured tight gas reservoirs. This study shows the effect of drainage pattern of the lenticular sand bodies on production performance, gas in place (GIP) estimation using P/Z vs Gp method, and ultimate gas recovery in tight gas formations. Numerical simulation approaches are used in order to understand the effect of hydraulic fracture parameters and also attribution of sand lens size and shape to the drainage pattern and gas recovery in hydraulically fractured tight sand gas reservoirs. The results highlighted that in tight gas reservoirs, sand lens size in the direction perpendicular to hydraulic fracture wings has the major impact on gas recovery. Drainage of gas from the reservoirs is controlled by the sand lens width, and the size of sand lenses in the direction parallel to the hydraulic fracture wings does not have significant effect on gas recovery. The drainage area of the tight gas reservoirs is limited to the area perpendicular to the hydraulic fractures wings, and therefore P/Z vs Gp method may underestimate the value of GIP calculated for the lenticular/elliptical shape sand lenses.