Capillary Pressure Effects on Estimating the Enhanced-Oil-Recovery Potential During Low-Salinity and Smart Waterflooding

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 481-496 ◽  
Author(s):  
Pål Østebø Andersen
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Wettability Alteration ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Low Salinity ◽  
Smart Water ◽  
Relative Permeability Curves

Summary Many experimental studies have investigated smart water and low-salinity waterflooding and observed significant incremental oil recovery after changes in the injected-brine composition. The common approach to model such enhanced-oil-recovery (EOR) mechanisms is by shifting the input relative permeability curves, particularly including a reduction of the residual oil saturation. Cores that originally display oil-wetness can retain much oil at the outlet of the flooded core because of the capillary pressure being zero at a high oil saturation. This end effect is difficult to overcome in highly permeable cores at typical laboratory rates. Injecting a brine that changes the wetting state to less-oil-wet conditions (represented by zero capillary pressure at a lower oil saturation) will lead to a release of oil previously trapped at the outlet. Although this is chemically induced incremental oil, it represents a reduction of remaining oil saturation, not necessarily of residual oil saturation. This paper illustrates the mentioned issues of interpreting the difference in remaining and residual oil saturation during chemical EOR and hence the evaluation of potential smart water effects. We present a mathematical model representing coreflooding that accounts for wettability changes caused by changes in the injected composition. For purpose of illustration, this is performed in terms of adsorption of a wettability-alteration (WA) component coupled to the shifting of relative permeability curves and capillary pressure curves. The model is parameterized in accordance with experimental data by matching brine-dependent saturation functions to experiments where wettability alteration takes place dynamically because of the changing of one chemical component. It is seen that several effects can give an apparent smart water effect without having any real reduction of the residual oil saturation, including changes in the mobility ratio, where the oil already flowing is pushed more efficiently, and the magnitude of capillary end effects can be reduced because of increased water-wetness or because of a reduction in water relative permeability giving a greater viscous drag on the oil.

scholarly journals Quantifying the Low Salinity Waterflooding Effect

Energies ◽  
2021 ◽  
Vol 14 (7) ◽  
pp. 1979
Author(s):  
Omar Chaabi ◽  
Mohammed Al Kobaisi ◽  
Mohamed Haroun
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Laboratory Scale ◽  
Residual Oil ◽  
Oil Saturation ◽  
Low Salinity ◽  
Low Salinity Waterflooding ◽  
Reservoir Conditions ◽  
Salinity Water ◽  
Relative Permeability Curves

Low salinity waterflooding (LSW) has shown promising results in terms of increasing oil recovery at laboratory scale. In this work, we study the LSW effect, at laboratory scale, and provide a basis for quantifying the effect at field scale by extracting reliable relative permeability curves. These were achieved by experimental and numerical interpretation of laboratory core studies. Carbonate rock samples were used to conduct secondary and tertiary unsteady-state coreflooding experiments at reservoir conditions. A mathematical model was developed as a research tool to interpret and further validate the physical plausibility of the coreflooding experiments. At core scale and a typical field rate of ~1 ft/day, low salinity water (LS) resulted in not only ~20% higher oil recovery compared to formation water (FW) but also recovered oil sooner. LS water also showed capability of reducing the residual oil saturation when flooded in tertiary mode. The greater oil recovery caused by LSW can be attributed to altering the wettability of the rock to less oil-wet as confirmed by the numerically extracted relative permeability curves.

scholarly journals Mysteries behind the Low Salinity Water Injection Technique

2014 ◽  
Vol 2014 ◽  
pp. 1-11 ◽  
Author(s):  
Emad Waleed Al-Shalabi ◽  
Kamy Sepehrnoori ◽  
Gary Pope
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
History Matching ◽  
Water Injection ◽  
Residual Oil ◽  
Oil Saturation ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Low salinity water injection (LSWI) is gaining popularity as an improved oil recovery technique in both secondary and tertiary injection modes. The objective of this paper is to investigate the main mechanisms behind the LSWI effect on oil recovery from carbonates through history-matching of a recently published coreflood. This paper includes a description of the seawater cycle match and two proposed methods to history-match the LSWI cycles using the UTCHEM simulator. The sensitivity of residual oil saturation, capillary pressure curve, and relative permeability parameters (endpoints and Corey’s exponents) on LSWI is evaluated in this work. Results showed that wettability alteration is still believed to be the main contributor to the LSWI effect on oil recovery in carbonates through successfully history matching both oil recovery and pressure drop data. Moreover, tuning residual oil saturation and relative permeability parameters including endpoints and exponents is essential for a good data match. Also, the incremental oil recovery obtained by LSWI is mainly controlled by oil relative permeability parameters rather than water relative permeability parameters. The findings of this paper help to gain more insight into this uncertain IOR technique and propose a mechanistic model for oil recovery predictions.

Displacement Studies in Dolomite With Wettability Control by Octanoic Acid

1973 ◽  
Vol 13 (04) ◽  
pp. 221-232 ◽  
Author(s):  
N.R. Morrow ◽  
P.J. Cram ◽  
F.G. McCaffery
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Significant Influence ◽  
Octanoic Acid ◽  
Contact Angles ◽  
Wettability Alteration ◽  
Residual Oil ◽  
Relative Permeability Curves

Abstract Various nitrogen-, oxygen- and sulfur-containing compounds native to crude oils were screened for their effect on wettability as measured by contact angle. Solid substrates of quartz, calcite, and dolomite crystals were used to represent reservoir rock surfaces. With water and decane as liquids, contact angles were measured after a given polar compound was added to the oil phase. Contact angles measured at the two types of carbonate surfaces were generally similar. None of the nitrogen or sulfur compounds studied gave contact angles greater than 66 degrees on either quartz or carbonates. Of the oxygen-containing compounds, octanoic acid gave the widest range of contact angle - 0 degrees to 145 degrees on dolomite - over a molar concentration range up to 0.1. Capillary - pressure and relative-permeability curves were obtained for water and solutions of octanoic acid in oil, using packings of powdered dolomite as the porous medium. Because of a slow reaction between dolomite and octanoic acid, which was not revealed by standard contact angle studies, special precautions were needed to ensure satisfactory wettability control during displacement tests. Capillary-pressure drainage curves were measured at six contact angles, ranging from 0 degrees to 140 degrees. Drainage-imbibition cycles for three packings of distinctly different particle size were measured at contact angles of 0 degrees and 49 degrees. The effect of contact angle on imbibition capillary pressures was close to that found previously for porous polytetra-fluoroethylene, whereas there was comparatively polytetra-fluoroethylene, whereas there was comparatively less effect on drainage behavior-steady-state relative permeability curves exhibited distinct differences for contact angles of 15 degrees, 100 degrees and 155 degrees. Introduction Waterflooding is the most successful and widely applied improved recovery technique. Its application in Alberta has, on the average, more than doubled the recovery obtained by primary depletion. However, even after waterflooding, it is estimated that two-thirds of the discovered oil remains unrecovered. Interfacial forces acting during waterflooding lead to the entrapment of large quantities of residual oil in the swept zones. Considerable attention has been paid to recovering this oil through new recovery methods in which the interface is eliminated as in miscible processes, or the interfacial tension is drastically lowered, as in surfactant floods. Such processes involve a high initial cost for an injected solvent or surfactant bank. Recently released information on a variety of such improved recovery techniques has not been altogether encouraging with regard to developing economical processes. A distinct alternative to eliminating the interface is to understand it and learn how it can be manipulated to give increased waterflood recoveries. A prospect for improved recovery at interfacial tensions of the order normally encountered in reservoirs lies in a favorable adjustment of wettability by incorporating small amounts of low-cost additives in the floodwater. A first step in developing the technology of improved recovery by wettability alteration is to determine the effect of wettability alteration on displacement in systems of uniform wettability. It has been shown that, even in the "near miscible" surfactant processes, wettability can still have a significant influence on the extent to which interfacial tension must be lowered in order to mobilize residual oil. At the time when waterflooding first found widespread use, wettability was recognized as a variable that might well have a significant influence on recovery performance. Reservoir wettability and the role of wettability in displacement has been the subject of some 50 or so publications. Even so, many aspects of wettability are not well understood and there is no general agreement on a satisfactory method of characterizing it. Opinions as to the optimum wettability condition for recovery cover the spectrum from strongly water-wet through weakly water-wet or intermediately wet to strongly oil-wet. It has recently been suggested that a mixed wettability condition can give high ultimate recoveries. SPEJ P. 221

Peripheral Low Salinity Water Injection Handil Case Study

2021 ◽  
Author(s):  
Julfree Sianturi ◽  
Bayu Setyo Handoko ◽  
Aditya Suardiputra ◽  
Radya Senoputra
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Water Flooding ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Abstract Handil Field is a giant mature oil and gas field situated in Mahakam Delta, East Kalimantan Indonesia. Peripheral Low Salinity Water injection was performed since 1978 with an extraordinary result. The paper is intending to describe the success story of this secondary recovery by low salinity water injection application in the peripheral of Handil field main zone, which successfully increased the oil recovery and brought down the remaining oil saturation beyond the theoretical value of residual oil saturation number. Water producer wells were drilled to produce low salinity water from shallow reservoirs 400 - 1000 m depth then it was injected to main zone reservoirs where the main accumulation of oil situated. This low salinity water reacted positively with the rock properties and in-situ fluids which was described as wettability alteration in the reservoir. It is related to initial reservoir condition, connate water saturation, rock physics and connate water salinity. This peripheral scheme then observed having the sweeping effect on top of pressure maintenance due to long period of injection. The field production performance was indicating the important reduction of residual oil saturation in some reservoirs with continuous low salinity water injection. From static Oil in Place calculation, some reservoirs have high current oil recovery up to 80%. This was proved by in situ residual oil saturation measurement which was performed in 2007 and 2011. It was indicating the low residual saturation as low as 8% - 15%. This excellent result was embraced by a progressive development plan, where water flooding with pattern and chemical injection will be performed later on. The continuation of this peripheral injection is in an on-going development with patterns injection which is called water flooding development. An important oil recovery can be achieved with a simple scheme of low salinity injection, performed in a close network injection, where the water treatment is simple yet significant oil gain was recovered. This innovation technique brings more revenue with less investment compared to chemical EOR injection.

scholarly journals Low salinity effects on oil recovery performance: underlying physical mechanisms and practical assessment

2020 ◽  
Vol 75 ◽  
pp. 37
Author(s):  
B. Bourbiaux
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Salinity Effects ◽  
Low Salinity ◽  
Clastic Rocks ◽  
Ionic Force ◽  
Brine Concentration

This paper is a tentative synthesis of the main knowledge and experience gained from recent studies and application of Low Salinity Water Injection (LSWI) in carbonate and clayey silico-clastic rocks. A physical model based on ionic force is presented to explain the so-called Dual Layer Expansion (DLE) mechanism often invoked to account for the Low Salinity Effects (LSE) on rock wettability and oil recovery. The role played by the Multi Ion Exchange (MIE) mechanism is clarified, at least for clayey rocks. Eventually, the proposed physical analysis shows the complementary roles that injected brine concentration and composition can play on waterflood recovery efficiency depending on the Crude Oil Brine Rock (COBR) system under consideration. To account for the diversity of COBR systems, a straightforward modelling methodology is then proposed to simulate laboratory LSWI tests on a case-by-case basis and infer the actual evolution of residual oil saturation with brine concentration and/or composition. The simulation involves a wettability driver that may be either the global salinity or the square root of ionic force. The analysis of published results actually shows that the latter predicts low salinity effects on residual oil saturation better than the former. Hopefully, this paper contributes to the understanding of the DLE and MIE mechanisms induced by a smart water injection and provides a simple and robust methodology to simulate the reference coreflood experiments that remain necessary to assess and optimize LSWI.

http://archives.datapages.com/data/ipa_pdf/2021/IPA21-BC-205.html

2021 ◽  
Author(s):  
J. Sianturi
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Water Flooding ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Handil Field is a giant mature oil and gas field situated in Mahakam Delta, East Kalimantan Indonesia. Peripheral Low Salinity Water injection was performed since 1978 with extraordinary results. This paper describes the success story of this secondary recovery by low salinity water injection application in the peripheral of Handil field main zone, which successfully increased the oil recovery and brought down the remaining oil saturation beyond the theoretical value of residual oil saturation. Water producer wells were drilled to produce low salinity water from shallow reservoirs 400 - 1000 m depth then it was injected to main zone reservoirs where the main accumulation of oil is situated. This low salinity water reacted positively with the rock properties and in-situ fluids which is described as wettability alteration in the reservoir. It is related to initial reservoir condition, connate water saturation, rock physics and connate water salinity. This peripheral scheme then observed having the sweeping effect on top of pressure maintenance due to long period of injection. The field production performance was indicating the important reduction of residual oil saturation in some reservoirs with continuous low salinity water injection. From static Oil in Place calculation, some reservoirs have high current oil recovery up to 80%. This was proved by in situ residual oil saturation measurement which was performed in 2007 and 2011. It was indicating the low residual saturation as low as 8% - 15%. This excellent result was embraced by a progressive development plan, where water flooding with pattern and chemical injection will be performed later on. The continuation of this peripheral injection is in an on-going development with patterns injection which is called water flooding development. An important oil recovery can be achieved with a simple scheme of low salinity injection, performed in a close network injection, where the water treatment is simple yet significant oil gain was recovered. This innovation technique brings more revenue with less investment compared to chemical EOR injection.

Relationship between Residual Saturations and Wettability using Pore-Network Modeling

2021 ◽  
Author(s):  
Prakash Purswani ◽  
Russell T. Johns ◽  
Zuleima T. Karpyn
Keyword(s):  
Contact Angle ◽  
Oil Recovery ◽  
Network Modeling ◽  
Pore Network ◽  
Residual Oil ◽  
Residual Saturation ◽  
Oil Saturation ◽  
Pore Network Modeling ◽  
Residual Oil Saturation ◽  
Eor Processes

Abstract The relationship between residual saturation and wettability is critical for modeling enhanced oil recovery (EOR) processes. The wetting state of a core is often quantified through Amott indices, which are estimated from the ratio of the saturation fraction that flows spontaneously to the total saturation change that occurs due to spontaneous flow and forced injection. Coreflooding experiments have shown that residual oil saturation trends against wettability indices typically show a minimum around mixed-wet conditions. Amott indices, however, provides an average measure of wettability (contact angle), which are intrinsically dependent on a variety of factors such as the initial oil saturation, aging conditions, etc. Thus, the use of Amott indices could potentially cloud the observed trends of residual saturation with wettability. Using pore network modeling (PNM), we show that residual oil saturation varies monotonically with the contact angle, which is a direct measure of wettability. That is, for fixed initial oil saturation, the residual oil saturation decreases monotonically as the reservoir becomes more water-wet (decreasing contact angle). Further, calculation of Amott indices for the PNM data sets show that a plot of the residual oil saturation versus Amott indices also shows this monotonic trend, but only if the initial oil saturation is kept fixed. Thus, for the cases presented here, we show that there is no minimum residual saturation at mixed-wet conditions as wettability changes. This can have important implications for low salinity waterflooding or other EOR processes where wettability is altered.

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