Shehadeh K. Masalmeh

The effect of wettability heterogeneity on capillary pressure and relative permeability

Abstract 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 the core or pore scale. In a previous paper, we reported on a series of centrifuge experiments performed to study the effect of wettability heterogeneity on capillary pressure. An experimental technique, named cyclic aging, was developed to create regions of different wetting in the same core sample. In this paper, the work is extended to study the effect of wettability heterogeneity on both capillary pressure and relative permeability curves using centrifuge, continuous injection and steady state techniques. The experimental procedure consists of three steps: (1) the core plug is fully saturated with brine and subsequently a drainage experiment is performed targeting an initial oil saturation S oi , (2) after aging, oil is displaced by water to residual oil saturation S or , and (3) oil is injected targeting higher initial oil saturation. In the secondary drainage experiment (step 3), oil first displaces water from the pores exposed to crude oil in primary drainage (step 1) and then enters fresh pores not exposed to crude oil before. In our previous study, it was found that wettability heterogeneity caused a step change in capillary pressure which correlated very well with the saturation at which wettability contrast was expected. However, the height of the step could not be explained by wettability contrast and/or water trapping alone. An experimental artifact caused by the centrifuge technique made the step higher than expected. The experimental artifact was the result of the nonuniform saturation profile developed across the core at the end of the centrifuge experiment. In this study, new techniques were used which resulted in a uniform saturation profile along the core sample during the primary drainage experiment. It was found that in this case the step in the capillary pressure is determined by wettability contrast and water trapping. It was also found that the relative permeability curve changes its characteristics when oil accesses the pores not previously exposed to crude oil. The results of this study show that (1) only the part of the pore space exposed to crude oil undergoes wettability changes on both core scale and pore scale, and (2) ignoring wettability heterogeneity can lead to large errors in the estimated two phase flow functions with important consequences with respect to fluid flow in porous media.

Wettability Alteration and Foam Mobility Control in a Layered, 2D Heterogeneous Sandpack

In a layered 2-D heterogeneous sandpack with a 19:1 permeability contrast that was preferentially oil-wet, the recovery by waterflood was only 49.1% of original oil-in-place (OOIP) due to injected water flowing through the high-permeability zone leaving the low-permeability zone unswept. In order to enhance oil recovery, an anionic surfactant blend (NI) was injected that altered the wettability and lowered the interfacial tension (IFT). Once IFT was reduced to ultra-low values, the adverse effect of capillarity retaining oil was eliminated. Gravity-driven vertical counter-current flow then exchanged fluids between highand low-permeability zones during a 42-day system shut-in. Cumulative recovery after a subsequent foamflood was 94.6% OOIP even though foam strength was weak. Recovery with chemical flood (incremental-recovered-oil/waterflood-remaining-oil) was 89.4%. An alternative method is to apply foam mobility control as a robust viscous force dominant process with no initial surfactant injection and shut-in. The light crude oil studied in this paper was extremely detrimental to foam generation. However, the addition of lauryl betaine to NI at a weight ratio of 1:2 (NI : lauryl betaine), made the new NIB blend a good foaming agent with and without the presence of the crude oil. NIB by itself as an IFT reducing and foaming agent is shown to be effective in various secondary and tertiary alkaline/surfactant/foam (ASF) processes in water-wet 1-D homogeneous sandpacks, and in an oil-wet, heterogeneous layered system with a 34:1 permeability ratio.

Laboratory investigation of low salinity waterflooding for carbonate reservoirs

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). The results of the study show higher oil recovery as a result of reducing injected water salinity in both core flood and spontaneous imbibitions experiments. Core flood experiments showed an increase in oil recovery by 3 to 5 % of OOIP, while spontaneous imbibitions experiments showed an increased by 16 to 21 %. Additionally, spontaneous imbibitions experiments provide direct evidence of wet ability change by the LSW. The study also shows that the increase in oil recovery was obtained at much higher water salinity than the one observed in the case of sandstone rock. However, no relation was found between oil/brine IFT and ionic exchange analysis and the observed response of LSW in core flood experiments.

Studying the effect of wettability heterogeneity on the capillary pressure curves using the centrifuge technique

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.

The Effect of Wettability on Saturation Functions and Impact on Carbonate Reservoirs in the Middle East

Wettability is an important factor, which affects the flow behavior in oil reservoirs. It has a profound effect on the shape of relative permeability and capillary pressure curves and consequently on oil displacement processes in porous media. This paper presents experimental measurements on core samples where the effect of wettability is investigated on connate water, residual oil, oil and water permeability end points, relative permeability and capillary pressure curves. The paper summarizes the main findings of few years of data collection on several cores from different carbonate fields in the Middle East, and a comparison with clastic data is made when appropriate. The data shows very low connate water for most carbonate fields investigated in this study even for low permeability rocks, 1 md. The residual oil saturation after restoring wettability was measured to be less than 10% for both carbonate and sandstone fields. For water-wet samples a residual oil of around 30% is measured. A distinct difference was found in the dependence of residual oil saturation on initial oil saturation for water-wet and mixed-wet cores. For water-wet samples Sor increased almost linearly with Soi, however; for mixed-wet samples Sor was found to be constant for a very wide range of Soi values. For water-wet samples we often measured high oil relative permeability end point, Kro(Swc)>1.0, and it decreased ∗ Current address: The author is currently working with Shell Abu Dhabi, email:Shehahdeh.Masalmeh@shelldub.simis.com as the wettability changed to mixed-wet or oil-wet. The water relative permeability end point is low for water-wet samples and increased for mixed-wet or oil-wet samples. As demonstrated in the field case discussed in this paper, the findings of this study have important implications for field development and hydrocarbon recovery. Introduction Wettability is a major factor that affects fluid flow behavior in porous medium. It has a profound effect on the shape of relative permeability and capillary pressure curves and consequently on oil displacement processes. The effect of wettability on fluid flow and electrical properties of porous medium has been extensively studied in the literature [1-6]. The objective of this study is to assess the effect of wettability on: • Capillary pressure

Low Salinity Flooding: Experimental Evaluation and Numerical Interpretation

Low Salinity Flooding (LSF) is an emerging technology to improve oil recovery for both sandstone and carbonate reservoirs. Extensive laboratory experiments investigating the effect of LSF are available in the literature. To quantify the low salinity effect, spontaneous imbibition and/or tertiary waterflooding experiments have been reported. In only a few published cases, the experimental data was interpreted using numerical simulation to derive relative permeability curves for both low and high salinity water, to be used in field simulation. A critical review of the literature data shows a wide spread in the LSF response in both pressure and recovery. Moreover, most of the flooding experiments reported in the literature are performed at a low flow rate, of ~1 ft/day, which may lead to a significant capillary end effect and, consequently, to a possible overestimation of the LSF effect. The focus of this paper is on: 1- The experimental procedures used for proper evaluation of the LSF effect; 2- Reporting experimental data performed on sandstone samples in both tertiary and secondary mode waterflood; 3-The numerical interpretation of the laboratory data to obtain relative permeability and capillary pressure curves for both high salinity (HS) and low salinity (LS) water, to be used in reservoir simulation to quantify the benefit of LSF on reservoir scale and 4- Investigating whether the tertiary flooding experiments can be used to derive relative permeability curves for both HS and LS waterflooding. The main conclusions of the study are: 1- While spontaneous imbibition (SI) experiments could provide an indication of a potential low salinity effect, they are not sufficient to quantify the effect in flooding experiments; 2- The LSF effect measured during low rate flooding experiments (i.e., field rate) is not representative for the field scale as it is usually dominated by capillary end effect. Therefore, the low rate (raw) coreflood data will suggest a larger LSF benefit than would actually be the case; 3- The tertiary mode experiments cannot be used to derive the LS relative permeability curves as it only spans a narrow saturation range during LSF and 4- Both tertiary and secondary mode corefloods performed using multi-rates are required to obtain relative permeability curves for HS and LS water.

High Oil Recoveries from Transition Zones

Oil-water transition zones may contain a sizable part of a field’s STOIIP, specifically in low permeable sandstone and carbonate reservoirs. The amount of recoverable oil in a transition zone depends –among other things- on the distribution of initial oil saturation (S oi) as a function of depth and the dependency of the oils mobility, i.e., the residual oil saturation (S or) and relative permeability, on initial oil saturation. In this paper we present laboratory measurements of residual oil saturation and oil relative permeability as a function of initial oil saturation to properly characterize oil mobility in transition zone. We found that the residual oil saturation after water flooding showed, for the example studied here, no dependence on initial oil saturation. On the other hand we found that there is a clear trend in the imbibition oil relative permeability for decreasing S oi, i.e., for a given oil saturation oil mobility increases as initial oil saturation decreases. In other words, laboratory measurements show that the mobility of oil in the transition zone is much higher than conventional analysis would suggest. Consequently, in a given time span more oil can be produced from the transition zone than generally assumed and potentially large volumes of reserves can be added to reservoirs with large transition zones. The impact of the measured relative permeabilities and residual oil saturations on oil recovery has been quantified for a generic field example by numerical modeling using MoReS, the Shell group reservoir simulator. The recovery factor was found to increase from 32% using a single set of relative permeability curves for the whole field independent of initial oil saturation to 56% using the measured S oi dependent relative permeability curves. The water cut at abandonment was for both cases taken at 95%. Transition Zone Oil in transition zones has, in water-wet rocks, the tendency to fill the larger pores preferentially. As oil tries to enter a pore (originally water-wet) a certain threshold pressure has to be built up before the capillary pressure in the pore can be overcome and the oil can actually enter the pore. In the smaller pores the capillary effect is stronger and therefore higher pressure differentials are needed for oil to enter these pores, as a result larger pores are filled most easily. The largest pore throat will determine the minimum capillary rise above the free water level. The transition zone is the part of the reservoir where the saturations grade from 100% water in the water zone to an irreducible water saturation some vertical distance in the reservoir above the free water level, (Figure 1). In this interval both oil and water are mobile. Transition zone may vary in thickness from a few meters to over hundred meters and therefore it may contain a sizable part of the reservoir STOIIP. Usually the transition zone is not perforated for oil production because it is considered not economic. However, in the transition zone where only the largest pores are oil filled the relative oil mobility at a specific saturation is larger than at a similar saturation higher up in the reservoir where also small and poor conducting pores are oil filled. It has indeed been shown in this study that large volumes of oil can be produced from transition zones.

Low-Salinity Polymer Flooding: Improving Polymer Flooding Technical Feasibility and Economics by Using Low-Salinity Make-up Brine

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.

Demonstrating the Potential of Low-Salinity Waterflood to Improve Oil Recovery in Carbonate Reservoirs by Qualitative Coreflood

Low salinity waterflood (LSF) is a promising improved oil recovery (IOR) technology. Although, it has been demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in carbonate reservoirs is still not well-established as only a limited number of successful coreflood experiments are available in the literature. Therefore, the aim of this study was to examine the oil recovery improvement by LSF in carbonate reservoirs by performing coreflood experiments. This paper proposes an experimental approach to qualitatively evaluate the potential of LSF to improve oil recovery and alter the rock wettability during coreflood experiments. The corefloods were conducted on core plugs from two Middle Eastern carbonate reservoirs with a wide variation of rock properties and reservoir conditions. Seawater and several dilutions of formation brine and seawater were flooded in the tertiary mode to evaluate their impacts on oil recovery compared to formation brine injection. In addition, a geochemical study was performed using PHREEQC software to assess the potential of calcite dissolution by LSF. The experimental results confirmed that lowering the water salinity can alter the rock wettability towards more water-wet, causing improvement of oil recovery in tertiary waterflood in plugs from the two reservoirs. Furthermore, seawater is more favorable for improved oil recovery than formation brine as injection of seawater after formation brine resulted in extra oil production. This demonstrates that the brine composition plays an important role during waterflooding in carbonate reservoirs, and not only the brine salinity. It was also observed that oil recovery can be improved by injection of brines that cannot dissolve calcite based on the geochemical modeling study. This implies that calcite dissolution is not the dominant mechanism of IOR by LSF. To conclude, this paper demonstrates that low-salinity waterflood has a good potential as an IOR technology in carbonate reservoirs. In addition, the proposed experimental approach ensures the verification of LSF effect, either it is positive or negative. However, more work is required to further explore the most influential parameters affecting LSF response and explain the dominant mechanisms. Introduction Low salinity waterflood (LSF) is a relatively mature improved oil recovery technique for sandstone reservoirs. The concept of LSF, for sandstones, is to lower the ionic strength of the injected brine, which leads to an alteration of the rock wettability towards more water-wet and hence an improvement of oil recovery. Numerous laboratory studies demonstrated the effect of LSF by spontaneous imbibition tests and coreflood experiments (Bernard 1967, Jadhunandan and Morrow 1991, Yildiz and Morrow 1996, Tang and Morrow 1997, Lager et al. 2006, Ligthelm et al. 2009, Masalmeh et. al. 2013). Furthermore, published data confirmed the positive response of LSF at the field scale (Webb et al. 2004, Lager et al. 2008, Vledder et al. 2010). However, the potential of LSF for carbonate reservoirs has not been well investigated. Several spontaneous imbibition tests were performed on Stevns Klint outcrop chalk (Austad et al. 2005, Zhang and Austad 2006, Strand et al. 2006). The results demonstrated the wettability alteration towards more water-wet by seawater or modified seawater. Increasing the sulfate concentration in seawater resulted in more change of wettability towards waterwetness. Ferno et al. (2011) performed spontaneous imbibition tests on different chalk outcrops (Stevns, Rordal, and Niobrara) using brines with and without sulfate. The effect of adding sulfate to the brines on wettability alteration was observed only in plugs from Stevns Klint chalk, but not from the other 2 chalk types. Webb et al. (2005) performed

Improved Characterisation And Modelling Of Carbonate Reservoirs For Predicting Waterflood Performance

Carbonate reservoirs are highly heterogeneous and often show oil-wet or mixed-wet characteristics. Both geological heterogeneity and wettability have strong impact on capillary pressure (Pc) and relative permeability (Kr) behaviour, which is controlled by the pore size distribution, interfacial tension and interactions between rock and fluids as well as the saturation history. Capillary pressure data are essential input in both static and dynamic modelling of heterogeneous carbonate reservoirs. Drainage Pc is generally used for initialising reservoir static models while imbibition Pc is used to model secondary and tertiary recovery processes. The objective of this paper is to present an improved reservoir characterisation and modelling procedure for predicting waterflood performance of a Cretaceous carbonate reservoir in the Middle East. We focus on the characterisation of multiphase fluid flow properties, in particular the capillary pressure characteristics in both drainage and imbibition, and their assignments in reservoir simulation models. We show that for modelling initial saturation distribution in the reservoir, assigning saturation functions based on permeability or porosity classes alone is not adequate. Moreover the petrophysical correlations often used for clastic reservoirs (e.g., Leverett J-function) may not be applicable to carbonate reservoirs without careful pore-type examination and core analysis/calibration. A novel procedure is described to derive imbibition capillary pressure curves from the primary drainage Pc curves taking into account of wettability and fluid trapping. The results lead to an improved understanding of capillary pressure characteristics in carbonate reservoirs, in particular, the contact angle distributions and hysteresis behaviour in both drainage and imbibition. This paper also presents a mathematical model for implementing both drainage and imbibition capillary pressure functions in dynamic reservoir simulation. This model takes into account the complex pore size distribution and wettability characteristics in carbonates as observed in experimental special core analysis (SCAL) measurements. Furthermore, how to assign imbibition Pc for the different porosity and permeability classes will be examined and its impact on modelling waterflooding performance and remaining oil saturation distributions assessed. Introduction The complexity of carbonate reservoirs and the importance of a consistent approach in defining rock types have been a subject of several recent papers (Marzouk et al. 2000; Ramakrishnam et. al. 2000; Leal et. al. 2001; Porrai and Campos 2001; Giot et.al 2000; Silva et.al. 2002; Hamon 2002; Masalmeh and Jing 2004). Current practices in general are either based on petrophysical properties (i.e., porosity, permeability and drainage Pc curves) or geological description (facies and depositional environment) or a combination of both. The underlying assumption is that static rock characterisation and the resultant rock-typing scheme remain valid when assigning saturation functions (Pc & Kr) in dynamic reservoir modelling. In this paper, we will incorporate conventional core analysis (porosity, permeability), thin section and SEM analysis, mercury-air capillary pressure (Pc)/ NMR with special core analysis data, in particular, the imbibition Pc and residual oil saturation. Several experimental techniques are available to measure capillary pressure (Pc) curves, both in drainage and imbibition cycles. Mercury injection is frequently used for measuring drainage Pc curves as the technique is relatively cheap, fast and requires relatively straightforward data interpretation. The measured data, however, need to be converted to in situ reservoir conditions by taking into account the differences in interfacial tension and contact angle between the rock/fluid systems used in the laboratory and that found in reservoir. The porous-plate equilibrium method is a reliable and accurate technique for measuring Pc in drainage and imbibition under representative reservoir conditions of fluids, pressure and temperature. The main drawback of this technique is the lengthy time required to reach capillary equilibrium, which renders the technique impractical for certain field applications especially for tight and heterogeneous carbonates. The multispeed centrifuge method can be used for both drainage and imbibition Pc measurements using representative reservoir fluids. Compared with the porous-plate equilibrium technique, IPTC 11722 Improved Characterisation and Modelling of Carbonate Reservoirs for Predicting Waterflood Performance S.K. Masalmeh and X.D. Jing, Shell Technology Oman