Shehadeh Masalmeh - Academia.edu (original) (raw)

Papers by Shehadeh Masalmeh

SPE reservoir evaluation & engineering, Apr 19, 2007

An oil/water capillary transition zone often contains a sizable portion of a field's initial oil ... more An oil/water capillary transition zone often contains a sizable portion of a field's initial oil in place, especially for those carbonate reservoirs with low matrix permeability. The field-development plan and ultimate recovery may be influenced heavily by how much oil can be recovered from the transition zone. This in turn depends on a number of geological and petrophysical properties that influence the distribution of initial oil saturation (S oi) against depth, and on the rock and fluid interactions that control the residual oil saturation (S or), capillary pressure, and relative permeability characteristics as a function of initial oil saturation. Because of the general lack of relevant experimental data and the insufficient physical understanding of the characteristics of the transition zone, modeling both the static and dynamic properties of carbonate fields with large transition zones remains an ongoing challenge. In this paper, we first review the transition-zone definition and the current limitations in modeling transition zones. We describe the methodology recently developed, based on extensive experimental measurements and numerical simulation, for modeling both static and dynamic properties in capillary transition zones. We then address how to calculate initial-oil-saturation distribution in the carbonate fields by reconciling log and core data and taking into account the effect of reservoir wettability and its impact on petrophysical interpretations. The effects of relative permeability and imbibition capillary pressure curves on oil recovery in heterogeneous reservoirs with large transition zones are assessed. It is shown that a proper description of relative permeability and capillary pressure curves including hysteresis, based on experimental special-core-analysis (SCAL) data, has a significant impact on the field-performance predictions, especially for heterogeneous reservoirs with transition zones. * Currently with Shell Technology Oman (STO). ** Currently with Petroleum Development Oman (PDO).

All Days, Mar 31, 2014

The decrease in the residual oil saturation by polymer flooding with a high visco-elasticity solu... more The decrease in the residual oil saturation by polymer flooding with a high visco-elasticity solution has been widely addressed in the past few years. The effect of the polymer solution visco-elasticity on the microscopic sweep efficiency was studied experimentally in a range of length scales, from micromodels through core floods to full field application. In most of the micromodel and core flooding experiments, a comparison was made between the effect of glycerol and polyacrylamide solutions on the oil recovery, because glycerol does not exhibit elastic behavior (only viscous), while polyacrylamide solutions do.In this paper it is discussed that the use of glycerol in combination with brine and/or polymer solutions could yield erroneous results due to a very strong dependence of the glycerol viscosity on temperature and on mixing with water. Instead, in the current study a series of core floods was done in which several polymer solutions were injected with a wide spread in viscoelasticity but the same apparent viscosity to study the effect of visco-elasticity on oil recovery.The main conclusion of the study is that for the crude oil of high viscosity (~300 cP), hardly any effect was observed of increasing visco-elasticity on the oil recovery, even when both viscosity and flow rate were increased up to 300 cP and 3 ft/day, respectively. However, for the low viscosity crude (~9 cP), extra oil was recovered upon increasing the viscosity and/or flow rate of the polymer of high elasticity. No extra oil was recovered when using polymers of low elasticity even when using similar viscosity and flow rate, which indicates that it is an effect of elasticity and not of viscous stripping of residual oil saturation.Thus, this paper confirms that polymers of high elasticity can reduce the residual oil to water. However, since this effect was only observed by either increasing the polymer viscosity or injection rate, the main challenge for field application is injectivity of the polymer at such high viscosity or rate, therefore before embarking on field application an injectivity test is required.

Day 4 Thu, November 18, 2021, Dec 9, 2021

Polymer flooding has long been proposed to improve sweep efficiency in heterogeneous reservoirs w... more Polymer flooding has long been proposed to improve sweep efficiency in heterogeneous reservoirs where polymer enhances cross flow between layers and forces water into the low permeability layers, leading to more homogeneous saturation profile. Although this approach could unlock large volumes of by-passed oil in layered carbonate reservoirs, compatibility of polymer solutions with high salinity - high temperature carbonate reservoirs has been hindering polymer injection projects in such harsh conditions. The aim of this paper is to present the laboratory work, polymer injection field test results and pilot design aimed to unlock target tertiary oil recovery in a highly heterogeneous mixed to oil-wet giant carbonate reservoir. This paper focuses on a highly layered limestone reservoir with various levels of cyclicity in properties. This reservoir may be divided in two main bodies, i.e., an Upper zone and a Lower zone with permeability contrast of up to two orders of magnitude. The main part of the reservoir is currently under peripheral and mid-flank water injection. Field observations show that injected water tends to channel quickly through the Upper zone along the high permeability layers and bypass the oil in the Lower zone. Past studies have indicated that this water override phenomenon is caused by a combination of high permeability contrast and capillary forces which counteract gravity forces. In this setting, adequate polymer injection strategy to enhance cross-flow between these zones is investigated, building on laboratory and polymer injection test field results. A key prerequisite for defining such EOR development scenario is to have representative static and dynamic models that captures the geological heterogeneity of this kind of reservoirs. This is achieved by an improved and integrated reservoir characterization, modelling and water injection history matching procedure. The history matched model was used to investigate different polymer injection schemes and resulted in an optimum pilot design. The injection scheme is defined based on dynamic simulations to maximize value, building on results from single-well polymer injection test, laboratory work and on previous published work, which have demonstrated the potential of polymer flooding for this reservoir. Our study evidences the positive impact of polymer propagation at field scale, improving the water-front stability, which is a function of pressure gradient near producer wells. Sensitivities to the position and number of polymer injectors have been performed to identify the best injection configuration, depending on the existing water injection scheme and the operating constraints. The pilot design proposed builds on laboratory work and field monitoring data gathered during single-well polymer injection field test. Together, these elements represent building blocks to enable tertiary polymer recovery in giant heterogeneous carbonate reservoirs with high temperature - high salinity conditions.

Journal of Petroleum Science and Engineering, Jul 1, 2020

Low-salinity waterflooding (LSF) is a relatively simple and cheap Enhanced Oil Recovery technique... more Low-salinity waterflooding (LSF) is a relatively simple and cheap Enhanced Oil Recovery technique in which the salinity of the injected water is optimized to improve oil recovery over conventional waterflooding. Sulfate-rich as well as diluted brines have shown promising potential to increase oil production in limestone core samples. To quantify the low-salinity effect, spontaneous imbibition and/or waterflooding experiments have been reported. This paper combines spontaneous imbibition, centrifuge and unsteady state (USS) coreflooding experiments to investigate low-salinity effects in carbonate samples. The experimental study used three brine compositions to investigate low-salinity effects. A high-saline Formation-water (salinity of 183.4 g/l), Seawater (43.8 g/l) and 100-times Diluted-seawater (0.4 g/l). Initially, a sequence of spontaneous imbibition experiments was conducted to screen the impact of connate and imbibing water composition on spontaneous oil recovery. After completing the spontaneous imbibition tests, the samples were drained inside a centrifuge to determine the impact of brine composition on residual saturation and capillary pressure. Moreover, three USS corefloodings were conducted to test the different brine compositions in secondary and tertiary injection mode. The spontaneous imbibition, centrifuge method and coreflooding tests showed a consistent trend. Compared to Formation-water and Seawater , Diluted-sea water demonstrated the most promising potential to recover oil efficiently. The numerical part of the study includes the transparent development of a numerical centrifuge and coreflooding model on the top of the open-source simulator DuMu x. The mathematical model formulation demonstrates that a simple numerical approach is sufficient to history match the centrifuge and coreflooding experiments. In line with the experimental data, the numerically derived capillary pressure and relative permeability showed an increasing water-wetting behavior as the salinity of the imbibing/injection water decreased. All implemented numerical models were validated against the commercially established Cydar software.

An integrated study has been carried out to understand the field performance and remaining oil di... more An integrated study has been carried out to understand the field performance and remaining oil distribution of a heterogeneous and oil-wet carbonate reservoir under waterflood. The reservoir under study is a layered system where strata measuring a few feet in thickness can be correlated field-wide. The reservoir consists of two main units, i.e. a Lower zone of generally low permeability layers and an Upper zone of high permeability layers inter-bedded with low permeability layers; the average permeability of the Upper zone is some 10-100 times higher than that of the Lower zone.

Summary New polymer based EOR schemes are proposed to increase sweep efficiency and oil recovery ... more Summary New polymer based EOR schemes are proposed to increase sweep efficiency and oil recovery from high temperature and high salinity carbonate reservoirs in Abu Dhabi. These reservoirs generally consists of two main geological zones, i.e., an Upper zone and a Lower zone with permeability contrast of up two orders of magnitude. The new EOR concepts rely on keeping the upper zone pressurized by continuous polymer injection and simultaneously injecting miscible gas or water into the lower zone. A lateral pressure gradient is maintained in the upper zone, providing gas or water confinement in the lower zone and improving sweep efficiency. Accordingly, a comprehensive de-risking program for the new polymer based EOR schemes was initiated which includes an extensive laboratory experimental program and field injectivity test to ensure that the identified polymer can be injected in the target formation below fracture pressure. The comprehensive experimental program and results were described in an earlier publication ( Masalmeh et. al., 2019 ) and the field injectivity test was also described by Rachapudi et. al., 2020 . The polymer injectivity test (PIT) consists of three main phases: water injection baseline, polymer injection with different rates and different polymer concentrations and chase water injection. The objective of this paper is to present the interpretation of the polymer injectivity test using a single well radial model. This PIT is the world first polymer injectivity test in carbonate under such harsh conditions and the polymer used in this test has never been field tested before. The model was built to integrate and assess the dynamic data collected during the PIT, incorporating laboratory experiments, and evaluating the impact of different parameters on the near-wellbore injectivity behavior. Interpretation of the PIT using a radial simulation model allowed to confirm that the qualified polymer can be injected and propagated in the extremely harsh conditions carbonate reservoirs, below fracture pressure and without well plugging. Despite the uncertainties and operational complexities presented during the PIT, a representative history match was obtained. More than 20 thousand sensitivity simulation runs were performed through a robust iterative optimization history match method. This workflow helped to address multiple uncertainties and captured many possible scenarios and validated laboratory parameters such as polymer bulk viscosity, in-situ rheology, RRF, adsorption, etc. The results of the PIT interpretation will be further utilized in the sector model and full field simulation models to investigate and design multi-well EOR pilots and full field development plans.

Proceedings, Apr 12, 2011

Gas injection is a proven enhanced oil recovery method especially for light oil reservoirs. Gas h... more Gas injection is a proven enhanced oil recovery method especially for light oil reservoirs. Gas has the ability to enhance hydrocarbon recovery beyond levels possible with primary and secondary recovery methods and leads to high displacement efficiency. H

E3S web of conferences, 2019

SCAL parameters (i.e., Relative Permeability and Capillary Pressure curves) are key inputs to und... more SCAL parameters (i.e., Relative Permeability and Capillary Pressure curves) are key inputs to understand and predict reservoir behavior in all phases of development. Techniques to measure relative permeability and capillary pressure have been well established and applied to a wide variety of core samples both from sandstone and carbonate reservoirs. On the other hand, we frequently encounter quality compromised data due to challenges in experimental procedures, lack of understanding of measurement techniques, and poor quality of raw data. As a result, relative permeability is often viewed as a parameter with large uncertainties and a fitting parameter in history matching. A special core analysis program was recently carried out on selected core samples from a deep-water sandstone reservoir in the Gulf of Mexico. In this frontier, relative permeability has been ranked among the top subsurface uncertainties. It greatly impacts the production forecast and field development plan. However, due to the high temperature, high salinity and fluid compatibility issues, the core measurements faced very specific challenges and a good relative permeability dataset has not been obtained in the past for this area. In this work, we demonstrate that a quality set of relative permeability data can be obtained through close collaboration across disciplines, a properly designed protocol, adequate engagement with the laboratory, timely QA/QC of experimental raw data, and appropriate interpretation incorporating numerical simulations. Well-defined and constrained relative permeability curves have been derived with the combination of steady state and centrifuge techniques. The average trend can be described by a residual oil saturation of 22%, end-point relative permeabilities of 0.6 and 0.2 to oil and water, respectively and Corey exponents between 2 and 3.

All Days, Oct 10, 2004

This paper was selected for presentation by an SPE Program Committee following review of informat... more This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE,

Capillary pressure and relative permeability hysteresis have been investigated on core samples wi... more Capillary pressure and relative permeability hysteresis have been investigated on core samples with different wetting characteristics. The relative permeability and capillary pressure curves depend on the direction of saturation changes and on the maximum and minimum achieved saturations. A conceptual model to explain the hysteresis trends in both the relative permeability and capillary pressure is presented. The model attributes hysteresis to a combination of 1) trapping of one phase by another, 2) contact angle hysteresis and 3) the wettability change of parts of the pore space after contact with crude oil. In the literature there is a lack of a complete and consistent physical model to describe the hysteresis phenomenon due mainly to the fact that experimental data is rather scarce. Most of the available data is for water-wet systems. Therefore, there is a need for measurements done on non-water-wet systems. The data presented in this paper is measured on core samples of different wettability, i.e., water-wet and non-water-wet core samples. The measurements have been carried out on both carbonate and sandstone core material using Centrifuge, Steady State, CAPRICI and Pc-probe techniques. The experimental data show that there is significant hysteresis in the capillary pressure between primary drainage, primary imbibition and secondary drainage curves especially for non-water-wet samples. Moreover, for non-water wet samples, the bounding imbibition (i.e., primary imbibition) and secondary drainage P c curves do not form a closed hysteresis loop. This is observed in both the bounding and scanning curves. We also found that water relative permeability curves exhibited either very little or no hysteresis at all except when considerable part of the pore space became oil-wet. On the other hand, oil relative permeability curves showed strong hysteresis between the primary drainage and primary imbibition curves for all wetting status, with very little hysteresis thereafter except for mixed to oil-wet plugs. Experimental data suggests that while contact angle hysteresis has a profound effect on capillary pressure hysteresis, it hardly affects relative permeability hysteresis.

Carbonate reservoirs in the Middle East are highly heterogeneous with complex porosity systems an... more Carbonate reservoirs in the Middle East are highly heterogeneous with complex porosity systems and mixed-wet matrix properties. These characteristics strongly affect reservoir performance under waterflooding. This paper concerns a highly layered limestone reservoir with various levels of cyclicity in properties and can be described at a high level as consisting of two main bodies, i.e., an Upper zone and a Lower zone with permeability contrast of up to two orders of magnitude. The main part of the reservoir is currently under waterflooding. Field observations show that injected water tends to channel quickly through the Upper zone along the high permeability layers and bypass the oil in the Lower zone. Past studies have indicated that this water override phenomenon is caused by a combination of high permeability contrast and capillary forces which counteract gravity forces. In this paper we will investigate different development options for such heterogeneous mixed-wet reservoirs aiming at improving recovery from the Lower zone: 1- Optimized waterflooding with infill wells, 2- Novel EOR options designed to overcome the capillary forces and improve vertical sweep. The EOR options include (a) polymer-assisted solutions consisting of injecting polymer in the Upper zone and water or miscible gas in the Lower zone; and (b) surfactant assisted solutions (foam and enhanced gravity drainage). The main conclusions of the study are: 1- Waterflooding is an efficient recovery mechanism for the Upper zone and tight well spacing is required to improve recovery from the Lower zone; 2- The EOR processes have the potential of improving recovery from the Lower zone; 3- The most attractive EOR schemes are the polymer-based options which, when compared to the optimized waterflooding/infill scenario, lead to much higher recovery, lower volumes of water injected and significantly less water cycling and the requirement of fewer wells. The polymer-assisted solutions also require injecting much lower polymer volumes compared to conventional polymer flooding. Simulation results show that the process(es) are robust to injection rates, vertical heterogeneity, well completions and a range of polymer viscosities.

This paper presents a special core analysis (SCAL) study aimed at carbonate rock characterisation... more This paper presents a special core analysis (SCAL) study aimed at carbonate rock characterisation and measurement of saturation functions for modelling water-oil displacement of a heterogeneous reservoir. A particular focus is made on the measurement of water-oil capillary pressure curves using the centrifuge and CAPRICIan in-house technique combining capillary pressure and resistivity measurements in multiple drainage and imbibition cycles. The basic rock characterisation includes thin section, SEM, NMR and mercury-air capillary pressure (Pc) measurements. Capillary pressure has been obtained in three cycles: oil displacing water starting from 100% water saturated plugs (primary drainage), water displacing oil starting from connate water after aging the plugs to restore reservoir wettability (imbibition) and finally oil displacing water starting from residual oil saturation (secondary drainage). The data show that, for the particular carbonate reservoir under investigation, the fluid flow properties such as residual oil saturation and imbibition capillary pressure curves do not show consistent correlation with conventional rock typing or facies classification. For example, imbibition capillary pressure showed significant variations for a set of samples having similar permeability, porosity, and drainage capillary pressure curves. Insights into pore geometry and pore-scale physics are essential to explain the fluid displacement characteristics. Dynamic SCAL data (i.e., water displacing oil capillary pressure and relative permeability data) need to be included in the identification of rock types during reservoir characterisation. The results of this study have important implications in the design, interpretation and application of laboratory SCAL programme and consequently on field development planning. Assigning saturation functions based on permeability or conventional rock typing is shown to be inadequate. Further research is needed to establish improved classification schemes for such types of heterogeneous carbonate reservoirs.

All Days, Sep 16, 2013

It is widely recognized that the determination of the amount and distribution of residual oil sat... more It is widely recognized that the determination of the amount and distribution of residual oil saturation (Sorw) is a significant factor in managing ongoing waterflooding and the selection of EOR methods that are applicable and economically suitable for oil reservoirs. Laboratory core flooding tests are often used to estimate the amount of Sorw. The same core samples are then usually subjected to EOR flooding experiments to estimate the extra amount of oil that can be recovered with the specific EOR option. Failure to accurately determine Sorw will lead to wrong estimates of recovery factor of both waterflooding and the subsequent EOR methods. Significant amount of data is available in the literature on determining Sorw and on the critical capillary or bond number to mobilize Sorw. However, most of the data are measured on sandstone rock and for water-wet conditions. In this study the focus is on 1- determination of Sorw in the laboratory for carbonate reservoirs, 2- The factors that affect Sorw, including capillary end effect, capillary and Bond numbers, initial oil saturation, rock permeability, rock heterogeneity and experimental techniques and 3- The use of numerical simulation as tool to aid proper interpretation of laboratory experiments. The main conclusions of the study are: 1- Performing the water flooding experiments at reservoir rates of ~1 ft/d will lead to overestimation of Sorw as the data can be dominated by capillary end effect; 2- The relative contribution of capillary end effect increases as the permeability increases especially for heterogeneous carbonate rocks; 3- There is no correlation between Sorw and rock permeability or porosity for the case understudy; 4- The critical capillary or bond number of non-water-wet carbonates is much higher than those reported in the literature for water-wet sandstone; thus experiments can be performed at higher rates than those expected in the field without the risk of de-saturation of Sorw and 5- Once an equilibrium between capillary and viscous (or gravity) forces is established, the remaining oil saturation is independent of the number of pore volumes injected. The data presented in this paper has significant impact on the design of any subsequent EOR process. It shows that the EOR target (after waterflood) is significantly reduced if the measurements are performed using high rates (or high centrifuge speed) to overcome capillary end effect. Moreover, for non-water wet rock surfactant flooding will require much higher reduction in IFT to mobilize residual oil saturation than for water-wet rocks.

Journal of Petroleum Science and Engineering, Apr 1, 2002

Abstract Wettability heterogeneity and its effect on fluid flow properties has been the subject o... more Abstract Wettability heterogeneity and its effect on fluid flow properties has been the subject of several papers in the past few years. This effect is usually studied by using composite cores made up of blocks of different wettability. In this work, wettability heterogeneity is created in the core by partial filling of the pore space with oil, which creates parts of different wetting in the core. The part accessed with oil will change its wettability while the rest will stay water-wet, which creates a core plug of heterogeneous wettability. The effect of heterogeneous wettability on the capillary pressure is studied in a systematic way using the centrifuge technique in combination with numerical simulation of the experimental data. The experimental procedure consists of the following steps: (1) the core plug is fully saturated with brine and subsequently, a drainage experiment is performed targeting initial oil saturation, S oi , (2) after aging, the oil is displaced by water to residual oil saturation, S or , and finally (3) oil is injected, targeting higher initial oil saturation. This procedure was repeated several times on the same plugs, each time targeting higher initial oil saturation. An interesting feature that has been observed is a discontinuity (step) in the capillary pressure curve when oil from a wettability-altered part accesses an unaltered (water-wet) part of the core. This step is believed to be due to wettability contrast between the two parts, the higher the contrast, the larger the observed step. Moreover, the size of this step allows for systematic study of the effect of aging and initial oil saturation on wettability alteration on pore scale. The results of this study show that aging a core sample at low oil saturation introduces significant wettability alteration in the pores filled with oil, while the rest of the core is not affected. This wettability alteration on the pore scale is difficult to capture by simple Amott index measurement. The results also suggest that aging time to restore wettability may decrease as oil saturation increases.

All Days, Jul 19, 2011

A new EOR scheme is proposed to improve sweep efficiency and oil recovery from heterogeneous mixe... more A new EOR scheme is proposed to improve sweep efficiency and oil recovery from heterogeneous mixed to oil-wet carbonate reservoirs. The reservoir under study is a highly heterogeneous and layered reservoir which can be described at a high level as consisting of two main bodies, i.e., an Upper zone and a Lower zone with a permeability contrast of up to a factor of 100. The main recovery mechanism currently applied is water flooding. Field data shows that injected water tends to travel quickly through the Upper zone along the high permeability layers and bypasses the low permeable Lower zone, which results in poor sweep of the Lower zone. It has been demonstrated in earlier publications that this water override phenomenon is caused by capillary forces which act as a vertical barrier and counteract gravity for mixed or oil-wet reservoirs. Polymer flooding has been proposed to improve sweep efficiency in heterogeneous reservoirs. In this paper we propose a new polymer based EOR option in which the water and polymer are injected simultaneously into the Lower and Upper zones, respectively. Injection of polymer into Upper zone serves to minimize cross-flow of injected water from the Lower zone and improves the sweep efficiency of both Upper and Lower zones. Compared to polymer injection alone, a much lower volume of polymer is required which has a significant positive impact on cost of this EOR process. Numerical simulations have been performed using a history matched sector model. The model forecasts show that significant sweep improvement of the Lower zone is achieved compared to conventional water or gas injection. The results also show that the process is stable and robust to reservoir lateral and vertical heterogeneity, variation in polymer viscosity and that the amount of polymer that is used can be limited by only injecting a polymer slug of 0.1 to 0.2 pore volume. It is also shown that the process can be implemented in secondary and tertiary mode, where in tertiary mode earlier handling of production water is required. Experimental work shows there are promising polymers that may be able to withstand the high reservoir temperature, high salinity and high concentration of divalent ions in the reservoir under study.

International Petroleum Technology Conference, 2014

Polymer flooding is a mature EOR technique, which is successfully applied in both sandstone and c... more Polymer flooding is a mature EOR technique, which is successfully applied in both sandstone and carbonate reservoirs. In ongoing polymer projects, make-up brine is either formation water, sea water or any available water sources like deep or shallow aquifers. In this paper we focus on the use of low salinity water as the make-up brine. The objectives of combining low salinity flooding (LSF) with polymer flooding are three-fold: • Using low salinity brine reduces the amount of polymer required to obtain the target viscosity, which may lead to significant cost reduction. • Combining the benefit of low salinity flooding with polymer flooding leads to higher oil recovery over conventional polymer flooding. • Enhancing the elasticity of polymers by using low salinity brine which may lead to reduced Sorw and increased oil recovery. In addition to the objectives mentioned above, the use of a low-salinity make-up brine can give other benefits, such as better polymer stability especially at high temperatures), lower sensitivity to polymer shear degradation, lower polymer adsorption and lower scaling and souring tendency. The paper will present 1- Experimental procedures for investigating the potential benefits of low salinity polymer on both the required polymer concentration and the oil recovery. 2- Experimental results for several field cases 3- De-risking activities that were undertaken to mitigate any potential negative impact of using low salinity polymer, in the areas of clay swelling, polymer shear sensitivity, mixing and adsorption. The paper concludes that low-salinity polymer flooding can significantly improve existing and anticipated polymer flooding projects by reducing polymer volumes and/or increasing oil recovery. Low-salinity polymer flooding provides opportunities to apply polymer flooding in high-salinity and high-temperature reservoirs, for which polymer flooding with produced or formation water would be technically unfeasible or uneconomic.

All Days, Nov 11, 2012

Low salinity water flooding (LSW) research has been gaining more momentum in recent years for bot... more Low salinity water flooding (LSW) research has been gaining more momentum in recent years for both sandstone and carbonate reservoirs. Published laboratory data and field tests have shown an increase in oil recovery by changing injected brine salinity, especially for sandstone reservoirs. It is widely accepted that low salinity water alters the wet ability of the reservoir rock from less to more water-wet conditions, oil is then released from rock surfaces and recovery is increased. The main objectives of the current study are to: test the potential of increasing oil recovery by LSW of a carbonate reservoir and to investigate the factors that control it. The impact of LSW on oil recovery was investigated by conducting core flood and spontaneous imbibitions experiments at 70 oC using Lekhwair limestone core samples, crude oil and synthetic brine (194,450 ppm) which was mixed with distilled water in four proportions twice, 5 times, 10 times and 100 times dilution brines. Moreover, both crude oil/brine interfacial tension measurements (IFT) and ionic exchange experiments were carried out at room temperature (25 oC).

Journal of Petroleum Science and Engineering, Sep 1, 2003

... The effect of wettability on fluid flow properties in porous media has been extensively studi... more ... The effect of wettability on fluid flow properties in porous media has been extensively studied, and is still a subject of highly active investigation. Most of the work has focused on cores of homogeneous wettability. Little attention has been paid to wettability heterogeneity effects at ...

Most of the oil remain trapped in the reservoir after both primary and secondary recovery stages.... more Most of the oil remain trapped in the reservoir after both primary and secondary recovery stages. Enhanced oil recovery (EOR) techniques are usually implemented in the tertiary stage to recover the trapped oil. Accordingly, the inaccurate determination of residual oil saturation after waterflooding (Sorw) in the secondary stage affects the success and economics of the EOR processes in the tertiary stage. Thus, the capillary desaturation curve (CDC) is usually introduced as guidance to estimate the mobilized residual oil. The objectives of this study include determining the true Sorw for carbonate Indiana limestone outcrops under harsh conditions, then investigating the effect of trapping number, permeability, and initial oil saturation on Sorw, and finally characterizing the CDC for carbonate rocks by further reducing the Sorw using surfactant flooding. For this purpose, six carbonate Indiana limestone outcrop samples with different permeabilities (4-69 mD) and fluid samples i.e., field-representative oil, formation water, seawater, and surfactant solutions were utilized. The drainage process was performed systematically using a coreflooding system to establish initial water saturation by injecting heavy oil followed by crude oil and aging for two weeks. Afterward, all six cores were subjected to spontaneous imbibition using Amott cell. This was further followed by forced imbibition using both ultra-centrifuge and coreflooding systems for comparison purposes and achieving Sorw condition. Finally, forced imbibition was performed on all cores using coreflood to generate CDC using three different surfactants with varying IFT values. The results showed that all rock samples achieved initial water saturation (Swi) in the range of 18-32% with no correlation between Swi and rock permeability. In addition, spontaneous imbibition tests showed slight oil production which reflect the oil-wetness of these cores used. It was noted that this slight production varied among cores with the same rock permeability range, which indirectly indicating the existence of heterogeneity within each permeability range. Furthermore, Sorw of 20-30% was reached using ultra-centrifuge and coreflooding method, indicating no correlation of permeability with Sorw. Based on the CDC studies, the critical trapping number was in the range between 10−5 and 10−4 for the tested cores, which is higher than the reported values in literature (10−8 to 10−6). This work provides a new insight into the understanding of capillary trapping effect on residual oil using CDC in carbonates. The complications in carbonate rocks, including the complex nature of high heterogeneity, mixed-to-oil wettability, high temperature, and high salinity, render accurate determination of true Sorw is a challenge at lab-scale. Sorw determination and CDC characterization aid in EOR screening to find the effective and economically viable methods for production enhancement.

Evaluation of petrophysical properties such as porosity, permeability, and irreducible water satu... more Evaluation of petrophysical properties such as porosity, permeability, and irreducible water saturation is crucial for reservoir characterization to determine the hydrocarbon initially in place and further optimize hydrocarbon production. However, estimation of these parameters is challenging for carbonate rocks due to their heterogeneity. One of the ways to determine petrophysical properties is the use of nuclear magnetic resonance (NMR), which involves applying a magnetic field to the formation and detecting signals emitted from pore spaces. The main objective of this study is to develop an empirical correlation for porosity, permeability, and irreducible water saturation by comparing NMR and laboratory measurements for carbonate rocks in the Middle East. Furthermore, machine learning (ML) approach was applied to predict these petrophysical parameters utilizing NMR data. Different ML algorithms such as tree-based and neural networks were trained to estimate these petrophysical properties of carbonate rocks. The obtained results from ML algorithms were further compared with core measurements to ensure their accuracy. The results showed that the use of T2 spectrum as an input provided more accurate results than NMR features. It can be proven by observing the performance of deep neural networks algorithm, where the models showed R2 values of 0.87 and 0.74 for porosity prediction using T2 and features extraction approaches, respectively. The same behavior was followed for the permeability estimations as deep neural networks model scored R2 = 0.81 (T2 approach) and R2 = 0.74 (features extraction approach). Similarly, determination of irreducible water saturation was more accurate using T2 approach (R2 = 0.87), whereas features extraction technique also exhibited a decent performance (R2 = 0.71). Also, T2 approach is more convenient since it is more straightforward to generate T2 spectrum from NMR measurements and use it for the ML models. Furthermore, based on the machine learning approach, gradient boosting and deep neural networks models performed with higher accuracy than other algorithms. This can be attributed to their strong configuration, which is able to find patterns between input and output parameters. This study provides more insight into petrophysical properties determined from NMR measurements in carbonates using ML techniques. This is useful in better characterizing carbonate reservoirs in the Middle East through accurate estimations of hydrocarbon resources and related reserves.