In-Situ Estimation of Relative Permeability and Capillary Pressure from the Joint Inversion of Array Resistivity and Formation Test Data

Liang, Lin; Zhu, Jianxi; Wang, Fan; Chen, Jie; Habashy, Tarek M.; Abubakar, Aria

doi:10.2118/187193-ms

Cited by 6 publications

References 27 publications

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Interpretation of formation permeability and pressure responses from wireline formation testing with consideration of interlayers

Yang

Chen

2018

Interpretation

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We have developed a workflow to interpret formation permeability in a hydrocarbon reservoir with consideration of interlayers by numerically simulating the measured pump-out flow and pressure responses from wireline formation testing (WFT). With the field data obtained from a dual packer tool in the deepwater Gulf of Mexico, we have developed and validated a high-resolution numerical model to simulate the fluid-sampling process together with transient pressure. History matching has been performed with field data to assess the effective thickness and then interpret the permeability for each flow unit. In addition to generating eight cases under various configurations of laminated layers, we use pressure buildup derivatives obtained from packers and observation probes as a diagnosis tool to examine the effect of the interlayer on WFT measurements. Oil-based mud-filtrate invasion affects the early-time behavior of pressure transients because of the associated changes in fluid viscosity and compositions. Low vertical permeability can behave as a vertical barrier for the flow in a WFT tool, indicating the difference contrast in permeability between individual flow units. As for the field case, effective water horizontal permeabilities for tests 1 and 2 are 14.0 and 10.6 mD, respectively. Low vertical permeability results in a distortion in the derivatives, particularly during the transition between flow regimes. In a laminated reservoir, a radial flow regime will develop when the radial length of interlayer is greater than the vertical formation interval and when the complete circular shape of interlayer is formed. It is recommended that any observation probe be positioned in or below the interlayer to accurately define the vertical communication of interlayers and its configuration. If dual packers and observation probes are located in the same zone, their pressure responses exhibit the same flow regimes; otherwise, different pressure responses can be developed in the observation probes when a partially sealing interlayer exists.

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Interpretation of formation permeability and pressure responses from wireline formation testing with consideration of interlayers

Yang

Chen

2018

Interpretation

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New Model for Wettability Change with Depth in Mixed-Wet Complex Carbonates

Ferreira

Stukan

Liang

et al. 2018

Day 3 Wed, November 14, 2018

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Oil-water relative permeability and capillary pressure are key inputs for multiphase reservoir simulations. These data are significantly impacted by the wettability state in the reservoir and by the pore space characteristics of the rock. However, in the laboratory, there are several challenges related to the validation and interpretation of the special core analysis (SCAL) measurements. They are mostly associated with the core preservation or restoration processes and resulting wettability states. To improve dynamic reservoir rock typing (DRRT) process, a new model, describing the change of wettability fraction with depth in mixed-wet reservoirs, is proposed. The proposed model is based on solid physics describing the interactions between the rock grain surfaces and the fluids filling the pore space. First, the model considers the oil migration from the source rock into the originally water-wet reservoir and the corresponding capillary pressure rise, as the height above the free water level (HAFWL) is progressively increased. Then, oil-wet and water-wet fractions are estimated for different static reservoir rock types (SRRT) and different HAFWL, based on the wettability change potential of the rock-fluid system and oil-water capillary pressure curves. Additionally, mixed-wet capillary pressure and relative permeability curves are estimated for both oil displacing water (drainage) and water displacing oil (imbibition) processes, based on the estimated mixed-wet fractions and single-wet curves. We discussed the model assumptions and its parameters’ uncertainties. We prepared a comprehensive sensitivity study on the impact of wettability variability with depth on oil recovery results. This study used a synthetic carbonate-reservoir simulation model, under waterflooding, by incorporating the concept of DRRT defined according to the different SRRT and estimated wettability fractions. The results showed a significant impact of wettability variability on oil in place and reserves estimates for waterflooding processes in typical complex, mixed-wet carbonate reservoirs, such as the ones found in the Brazilian Pre-Salt. We also discuss the potential impact of wettability change with depth on well logs like resistivity, nuclear magnetic resonance (NMR) and dielectric logs. The proposed reservoir wettability model and its corresponding DRRT workflow is relatively simple and widely applicable, and may significantly improve reservoir simulation and wettability uncertainty analysis. It also explicitly identifies the required wettability parameters to be obtained from laboratory experiments and well logs. Finally, the proposed model may be integrated with special core analysis, well logs and digital-rock analysis.

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Production Forecast and Optimization Utilizing In-Situ Determined Relative Permeability in a Highly Unconsolidated Sour Heavy Oil Clastic Reservoir

Ayyad

Dashti

AL-Nabhan

et al. 2019

SPE Middle East Oil and Gas Show and Conference

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In Umm Niqa field, Lower Fars (LF) is a shallow, unconsolidated, sour heavy oil and low-pressure sand reservoir. During the current appraisal and exploratory phases, oil production forecasts based on reservoir simulation models were observed to be significantly higher than actual production. Furthermore, unexpected early water breakthrough and the rapid increase in the water cut added more complexity to the reservoir production. This paper will focus on how these challenges were addressed with a unique workflow. If the reservoir is producing more than one phase, then relative permeability determination becomes essential for the production forecast as well as production optimization to delay the water breakthrough. Due to the unconsolidated nature of LF reservoir, it was challenging to perform coring operation in this environment. In the few cases where cores were obtained, it was almost impossible to perform the relative permeability analysis on the core plugs. Therefore, there was a need to obtain this information by exploring other technique or methodology. Hence in-situ relative permeability technique was implemented in three different wells. To address the relative permeability determination challenge, an innovative approach was implemented in three different wells. This approach determines the relative permeability at downhole conditions by utilizing the fluids clean-up and sampling data during the wireline downhole formation testing as well as some advanced petrophysical measurements such as the array resistivity, the nuclear magnetic resonance (NMR), and the dielectric dispersion. The data obtained were used as inputs for a multi-physics integrated workflow, which inverts for the relative permeability curves based on the modified Brooks-Corey model. In this paper, it will be demonstrated how the relative permeability results obtained from this technique in these three wells were applied to update the reservoir simulation models. The production forecasts were found to be significantly improved and close to the actual production figures. The early water breakthrough is better anticipated; therefore, the production rate can be adjusted to delay it and maximize the oil recovery. This method provides an alternative and efficient way to derive the relative permeability curves when it is challenging to obtain from the conventional core analysis techniques. This helped to better understand the number of wells required to be drilled to achieve the planned production target. This paper adds to the literature unique case studies where relative permeability determination is required, however, not possible to be obtained through conventional industry techniques such as core analysis due to a highly unconsolidated formation. Hence, an innovative workflow was adopted to measure the relative permeability at downhole conditions.

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In-Situ Estimation of Relative Permeability and Capillary Pressure from the Joint Inversion of Array Resistivity and Formation Test Data

Cited by 6 publications

References 27 publications

Interpretation of formation permeability and pressure responses from wireline formation testing with consideration of interlayers

Interpretation of formation permeability and pressure responses from wireline formation testing with consideration of interlayers

New Model for Wettability Change with Depth in Mixed-Wet Complex Carbonates

Production Forecast and Optimization Utilizing In-Situ Determined Relative Permeability in a Highly Unconsolidated Sour Heavy Oil Clastic Reservoir

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