DETERMINATION OF RESIDUAL OIL SATURATION IN A WATER AND GAS FLOODED GIANT OIL RESERVOIR USING CORE, CONVENTIONAL AND PULSED NEUTRON LOGS

2021 ◽  
Author(s):  
Mike Davenport ◽  
◽  
Rufat Guliyev ◽  
Kasim Sadikoglu ◽  
Pavel Gramin ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Clay Content ◽  
Oil Field ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Future Production ◽  
Open Hole ◽  
Pulsed Neutron

The understanding of residual saturation in an oil field in mid-development is essential for estimating the cumulative production achievable, optimizing the future production mechanisms planned for infill targets, development of adjacent reservoir levels and optimizing the design of future facilities. The ACG (Azeri, Chirag, Gunashli) field is a giant oil field located about 120 km offshore in the South Caspian Sea, Azerbaijan. The field consists of multiple stacked clastic reservoirs including the Fasila and Balakhany formations, each with variable oil water contacts, and variable presence and fill level of gas caps. The Fasila reservoirs have been nearly fully developed. Both down flank water injection and crestal gas injection have been employed to drive oil towards producers. These two processes result in different residual oil “trapping” mechanisms which have been explored by logging and coring. Future development of overlying reservoirs can be optimized if we understand the effectiveness of these mechanisms to improve oil recovery and understand produced fluid compositions to enable facilities optimization to handle them. Established techniques to measure the residual oil saturation in a live field depletion, such as conventional open hole logging, pulsed neutron logging and direct core measurements have been employed. This paper investigates the methodology of each technique and the comparison of the magnitude and uncertainty of the saturations obtained. The sands in the ACG main reservoirs are relatively massive and high Net-to-Gross (NTG), however their clay content and distribution is quite variable leading to a range of rock types which behave differently under fluid sweep, and the presence of both intra reservoir sealing shales and lateral sand quality variations lead to a complex pattern of sweep behavior. It was considered that conventional core would be the principle measurement, with the most direct estimation of downhole fluid conditions as well as achieving all other coring objectives. Core was acquired on two pilot wells, one behind the water flood front and another behind the expanding crestal gas cap. Several innovative core analysis techniques were employed. A full conventional log suite was acquired in both wells as well as an open hole pass of a multi detector pulsed neutron log in the crestal gas swept well. The analysis of all this data has led to some interesting conclusions. Previous core flood experiments had led the team to believe gas is more efficient than water in terms of lowering residual oil saturation and reaching higher recovery factors. The new core demonstrated that such low residual oil saturations are achieved more slowly than originally thought, though it didn't change the view of efficiency of gas displacement relative to water. It is also likely that reservoir heterogeneity has had a bigger impact on the variation in residual oil saturation between layers than reservoir quality itself.

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.

scholarly journals SURFACTANT-POLYMER FLOODING PERFORMANCE IN HETEROGENEOUS TWO-LAYERED POROUS MEDIA

2011 ◽  
Vol 12 (1) ◽  
pp. 31-38 ◽  
Author(s):  
Muhammad Taufiq Fathaddin ◽  
Asri Nugrahanti ◽  
Putri Nurizatulshira Buang ◽  
Khaled Abdalla Elraies
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Residual Oil ◽  
Oil Saturation ◽  
Reservoir Heterogeneity ◽  
Residual Oil Saturation ◽  
Layered Porous Media ◽  
Multiple Porosity

In this paper, simulation study was conducted to investigate the effect of spatial heterogeneity of multiple porosity fields on oil recovery, residual oil and microemulsion saturation. The generated porosity fields were applied into UTCHEM for simulating surfactant-polymer flooding in heterogeneous two-layered porous media. From the analysis, surfactant-polymer flooding was more sensitive than water flooding to the spatial distribution of multiple porosity fields. Residual oil saturation in upper and lower layers after water and polymer flooding was about the same with the reservoir heterogeneity. On the other hand, residual oil saturation in the two layers after surfactant-polymer flooding became more unequal as surfactant concentration increased. Surfactant-polymer flooding had higher oil recovery than water and polymer flooding within the range studied. The variation of oil recovery due to the reservoir heterogeneity was under 9.2%.

Laboratory Tests on Heavy Oil Recovery by Steam Injection

1983 ◽  
Vol 23 (03) ◽  
pp. 417-426 ◽  
Author(s):  
Philip J. Closmann ◽  
Richard D. Seba
Keyword(s):  
Pore Size ◽  
Heat Loss ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Steam Injection ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
The Core ◽  
Unconsolidated Sand

Abstract This paper presents results of laboratory experiments conducted to determine the effect of various parameters on residual oil saturation from steamdrives of heavy-oil reservoirs. These experiments indicated that remaining oil saturation, both at steam breakthrough and after passage of several PV of steam, is a function of oil/water viscosity ratio at saturated steam conditions. Introduction Considerable attention has been given to thermal techniques for stimulating production of underground hydrocarbons, particularly the more viscous oils production of underground hydrocarbons, particularly the more viscous oils and tars. Steam injection has been studied as one means of heating oil in place, reducing its viscosity, and thus making its displacement easier. place, reducing its viscosity, and thus making its displacement easier. A number of investigators have measured residual oil saturations remaining in the steam zone. Willman et al. also analyzed the steam displacement process to account for the oil recoveries observed. A number of methods have been developed to calculate the size of the steam zone and to predict oil recoveries by application of Buckley-Leverett theory, including the use of numerical simulation. The work described here was devoted to an experimental determination of oil recovery by steam injection in linear systems. The experiments were unscaled as far as fluid flow rates, gravity forces, and heat losses were concerned. Part of the study was to determine recoveries of naturally occurring very viscous tars in a suite of cores containing their original oil saturation. The cores numbered 95, 140, and 143 are a part of this group. Heterogeneities in these cores, however, led to the extension of the work to more uniform systems, such as sandpacks and Dalton sandstone cores. Our interest was in obtaining an overall view of important variables that affected recovery. In particular, because of the significant effect of steam distillation, most of the oils used in this study were chosen to avoid this factor. We also studied the effect of pore size on the residual oil saturation. As part of this work, we investigated the effect of the amount of water flushed through the system ahead of the steam front in several ways:the production rate was varied by a factor of four,the initial oil saturation was varied by a factor of two, andthe rate of heat loss was varied by removing the heat insulation from the flow system. Description of Apparatus and Experimental Technique Two types of systems were studied: unconsolidated sand and consolidated sandstone. The former type was provided by packing a section of pipe with 50–70 mesh Ottawa sand. Most runs on this type of system were in an 18-in. (45.72-cm) section of 1 1/2 -in. (3.8 1 -cm) diameter pipe, although runs on 6-in. (15.24-cm) and 5-ft (152.4-cm) lengths were also included. Consolidated cores 9 to 13 in. (22.86 to 33.02 cm) long and approximately 2 1/4 in. (5.72 cm) in diameter were sealed in a piece of metal pipe by means of an Epon/sand mixture. A photograph of two 9-in. (22.86-cm) consolidated natural cores (marked 95 and 143) from southwest Missouri, containing original oil, is shown as Fig. 1. In all steamdrive runs, the core was thermally insulated to reduce heat loss, unless the effect of heat loss was specifically being studied. Flow was usually horizontal except for the runs in which the effects of flushing water volume and of unconsolidated-sand pore size were examined. Micalex end pieces were used on the inlet end in initial experiments with consolidated cores to reduce heat leakage from the steam line to the metal jacket on the outside of the core. During most runs, however, the entire input assembly eventually became hot. SPEJ p. 417

Analysis of the Effect of Residual Oil on Particle Trapping During Produced-Water Reinjection Using X-Ray Tomography

SPE Journal ◽  
2010 ◽  
Vol 15 (04) ◽  
pp. 943-951 ◽  
Author(s):  
A.. Saraf ◽  
A.H. de Zwart ◽  
Peter K. Currie ◽  
Mohammad A.J. Ali
Keyword(s):  
Direct Observation ◽  
Particle Deposition ◽  
Produced Water ◽  
Water Injection ◽  
Residual Oil ◽  
Ct Scanner ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
X Ray ◽  
The Core

Summary Recently, it has been shown that the presence of residual oil in a formation can have a considerable influence on the trapping mechanisms for particles present in reinjected produced water (Ali 2007; Ali et al. 2005, 2007, 2009). This article reports on a further set of extensive coreflow experiments that confirm and extend these results. The tests were conducted in a computerized-tomography (CT) scanner, allowing direct observation of the buildup of particle deposition along the core. These experiments are relevant to operational issues associated with produced-water reinjection (PWRI). In many cases, produced water is injected into formations containing oil, so reduced oil saturation is achieved rapidly in the area around the well. Even if the well is outside the oil zone, trapped oil droplets are always present in produced water, and a residual-oil zone will gradually build up around the well. Major differences are found between the deposition profiles for fully water-saturated cores and the cores having residual-oil saturation. In particular, particles penetrate deeper into the core with residual-oil saturation, and considerably more particles pass completely through the core without being trapped. The X-ray technique allows direct observation during the experiment of the deposition process inside the core, eliminating the complicating effect of any external filter cake. As a result, an analysis can be performed of the deposition parameters relevant inside the core using deep-bed-filtration theory, and the results of this analysis are presented. In particular, it is shown that the values of the filtration function determined from the CT-scan (X-ray) data are consistent with those obtained from analysis of the effluent concentration. Moreover, both methods of analysis find quite clearly that the filtration coefficient increases with decreasing flow rate. The results indicate that formation damage near a wellbore during water injection will be reduced by the presence of residual oil, and that particles will penetrate deeper into the formation. The result is also relevant to injection under fracturing conditions because particle deposition in the wall of the fracture (where residual oil may be present) is one of the mechanisms governing fracture growth.

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.

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