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Abstract

Natural fractured petroleum reservoirs represent over 20% of the world’s oil and gas reserves. It plays an obvious role in oil exploration and makes a large contribution toward oil and gas production worldwide. The research tendency for natural fractured reservoir NFR has become more apparent in the last five to ten years because more fractured reservoirs are being developed as production from conventional reservoirs is declining. However, characterization of fractured reservoir is complex and presents unique challenges in comparison with conventional reservoir. There are several uncertainties in NFR characterization in exploration and field development strategies, especially in the early stages when little or even no data is available. Thus, it is urgent and necessary to collect the experiences from previous successful research to reduce risky level in such reservoir.

White Tiger is the biggest fractured basement reservoir up to now on the continental shelf of Viet Nam This reservoir has a complicated geological structure, very high heterogeneity, high temperature (more than 2750F) and closure stress (more than 8,000 psi); the collector model is quite different from that of conventional oil reservoirs in sediments rocks. The total OIIP of this field reached nearly 4 billions barells with 2000 meters of the oil bearing thickness and has been produced by more than 100 wells, tens of which flow at the rate of approximately one thousand barrels per day. Thus White Tiger has become one of the rarest oil fields worldwide. A huge volume of science researches has been done with great success. Many specify software, and calculation models, simulation geophysics and seismic interpretation have been successfully studied and applied to the basement reservoir. Based on experiences from White Tiger, a significant number of other oil fields in the fractured basement were discovered such as Rang Dong, Phuong Dong, Ruby, series of Black Lion, Yellow Lion, Brown Lion, Yellow Tuna, Southern Dragon and Turtle. The discovery of the oil reservoir in White Tiger fractured basement has changed the concept of oil and gas prospecting, exploration and development in Viet Nam and the region, being a considerable contribution to the world’s oil and gas science.

This paper reviews significant events in geological development and achievements in improved oil recovery by special methods for fractured granite basement reservoirs such as slant directional drilling, acid formation treatment, hydraulic fracturing of formation, polymer and surfactant flooding etc. With rich experience in exploration and production of hydrocarbon in fractured granite basement rocks over the past 20 years, it is worthy case study for both current and future development planning of NFR in the world.

Introduction

The continental shelf of Viet Nam was undergone many deformation stages. Since then, some basins were formed in which oil was accumulated in both sedimentary and granite basement rock reservoirs. Figure 1 shows the distribution of basins in the Viet Nam continental shelf and field location of Cuu Long basin. Authors mainly study a basement rock reservoir in Cuu Long basin, especially White Tiger and Dragon oil field which was produced with the huge oil amount.

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A Precious Achievements Review of Geological Development and IOR Application From 20 Sucessful Years in High Temperature Fractured Granite Reservoir Cuong T.Q. Dang, SPE, Ngoc T.B. Nguyen, SPE, and Wisup Bae, SPE, Sejong University; Byounghi Jung, MKE, Korea; and Jeonghwan Lee, Korea Gas Corporation

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The study of the fractured reservoir begins with a detailed analysis of the geometry, origin, morphology, density, width, trace length of fractures and the development of the porosity and storage capacity systems of the reservoir rocks. These parameters control the borehole diameter (relative to the spacing of fractures) and the trajectory of the boreholes (relative to the orientation of fractures). Three main rocks in the basement of Cuu Long basin, which contributes to the oil bearing reservoir, are complexes of Hon Khoai, Dinh Quan and Ankroet. These rocks were formed about 90 million to 240 million years ago (Hoang V.Q., 2008). The experiences of injection showed that the condition for stable displacement of the water-oil contact is that hydrodynamic gradient is only allowed to fluctuate around gravitation gradient. The basement fractured reservoirs contribute higher 50% amount of oil in the world. The success of the basement reservoir in Cuu Long basin is a good lesson for future exploration and production of oil.

Figure 1. Figure shows location of basin in the Viet Nam continental shelf and the White Tiger and Dragon oil field location in Cuu

Long basin (modified from Nguyen V.T. et al, 2008).

In addition, Vietsovpetro tried to find the solutions to maximize oil recovery efficiency. One of the exceedingly difficult issues to be solved is how to maintain reservoir pressure during the production process and control water level of production wells. Water and gas injection has been considered and studied theoretically. However, it is very difficult to improved oil recovery in this reservoir due to complex geological characterizarion a high temperature. This paper provides some successful research of the IOR in the White Tiger field.

Geological Development in Granite Basement Reservoir

History of Geological Structural Development

These basins, containing hydrocarbon in the continental shelf of Viet Nam, are characterized by complicated geological structures. Sedimentary formations were formed during continental collision, rifting and sagging of the crust of Earth in Late Mesozoic to Cenozoic periods. The basin rocks underwent five stages as follows (Do V.L. et al, 2008; Nguyen T.T. et al, 2008; Phan T.D., 2006; Nguyen Q.Q. et al, 2008; figure 2):

Early –Middle Jurassic collision stage

The subduction of the Pacific plate under the Asian plate formed the Bien Dong Sea (Nguyen T.T. et al, 2008; Nguyen Q.Q. et al, 2008). Indicator for this event, geologist investigated that the volcanic rocks of Pre-Tertiary basement in the southern region of Vietnam are distributed along an intrusive - extensive zone of Da Lat margin in Northeastern direction are the same age and lithology with the rock of basement.

These rocks are granite-granodiorite and diorite of Dinh Quan formation (Late Jurassic), Deo Ca Formation (Cretaceous) and some places of Ankroet formation (Late Cretaceous). Those rocks were found in both the basement of basin and exposed rocks in Da Lat zone (Trinh V.L., 2008; Figure 3). During these periods, the sub-stage such as subsidence – extension and compression occurred create the fault and fold with strike of NE-SW, E-W and N-S.

Late Jurassic – Cretaceous subduction –extension stage

This stage, the two processes of compression and extension occurred, and then NE-SW striking faults reactivated two times.

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Paleocene-Early Eocene Indochina tectonic peneplain stage

Following the above compression processes, the orogenetic activities uplifted basement rock and then create good conditions for weathering and erosion processes. The Cretaceous, Paleocene, and Eocene sedimentary formation absent in stratigraphic sequence (figure 4).

Rift stage from Late Eocene to Early Miocene

The rift process started with the extension processes. Those processes reactivated NE-SW striking faults and formed NW-SE striking faults. A large amount of sandstone, shale, and siltstone were deposited in grabens and deep troughs. And then in the Late Oligocene – Early Miocene periods the compression and thermal subsidence processes occurred and created NE-SW striking faults, fractures and joints.

Those faults, fractures and joints contributed important porosity for the basement reservoir in the Cuu Long and neighbor basins. The oil trap and bearing reservoir were formed in this stage. The end of this stage was marked by a maximum flooding boundary in which Rotali shale were found in stratigraphic sequence. It was a very good seal layer in some basins.

Stage from Middle Miocene to present

In this stage, the N-S, NNW-SSE striking compression and E-W, ENE-WSW striking extension created the path for the migration of oil into the basement reservoirs, accumulating there. Especially, those NE-SW striking faults mainly controlled the connectivity of oil flow in the basement reservoir. In the stage from Pliocene to Holocene, Basal volcanoes were activated in some places. In general, two fault systems with NE-SW and NW-SE strikes are two main faults, which contributes the porosity to store oil and are flow path of oil in the basement reservoir in the Cuu Long basin.

Figure 2. Tectonic phases and sedimentary accumulation of the White Tiger field (modified after Hoang, 2002)

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a. Granite rocks from the Cuu Long basin were described in thin section (after Trinh, 2006)

Figure 3. Granite rocks exposed in land at Dalat zone similar with the basement rock of the Cuu Long basin

Figure 4. Stratigraphic sequence of the White Tiger oil field

b. Cretaceous granite of Dinh Quan-Deo Ca suite and NE-striking dikes are formed at Deo Cau

c. The granite at Ke Ga and an open fault of 300

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Geological Characteristics of Basement Rock Reservoir

The most of basement rocks are hard and brittle. Fractures, faults and vugs contributed to the porosity. There are no pores in the matrix. In the continental shelf of Viet Nam, the basement reservoirs are located under the unconformities and on the highs of uplifted block which were weathered and eroded. These basement reservoirs were covered by younger sediments that played an important role such as source rocks and cap rocks (figure 5).

The basement rocks of Cuu Long basin are characterized by two types of rocks (metamorphic and igneous rocks). The igneous rocks consist of diorite and quartz diorite (granite), which were formed in the active continental margin arc setting. Metamorphic rocks are gneiss. Those rocks were found in Dragon and White Tiger oil field (Nguyen Q.Q. et al, 2008; Nguyen and Nguyen, 2008).

Reservoir quality depends on the development of secondary porosity. Two main types of porosity are tectonic porosity (fracture) and dissoluble porosity (cavern) (Nguyen T.T. et al, 2008; Phung D.H. et al, 2008; figure 6). The fractured zones are mainly concentrated at the top of the basement. This was observed in many wells of the Dragon and White Tiger oil fields (Nguyen Q.Q. et al, 2008). However, the thickness of basement reservoir is very thick. For example, the White Tiger basement reservoir has the oil-bearing thickness of nearly 2000 meters in length and a width of 30kms and 6-8kms, which is located on the central uplift zone of the Cuu Long basin (Hoang V.Q., 2008; figure 7). The depth of oil bearing zone varies from -3700m to -4450m at boundary of reservoir and from -4000m to -4200m at shallower intervals. With the characteristics of basement reservoir such as WT oil field, all wells were drilled in vertical direction.

Figure 5. Petroleum play concept in Cuu Long basin and fracture porosity in basement reservoir (after Phan T.C. and Pham V.T.,

2008).

Figure 6. Fractures and caverns in basement rock reservoir of Cuu Long basin (after Trinh, 2006)

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Figure 7. The model of White Tiger basement reservoir

Fracture Characteristics

Fracture properties

In the basement granite reservoirs, the fractures have played an important role for storing and transferring oil from reservoir to production well. Therefore, fracture properties are important parameters for studying reservoir characteristics. This section represents these fracture properties of basement rock in the Cuu Long basin to conduct a sample lesson for all granite basement reservoirs.

In the investigated and measured results of tectonic scratches on the onshore outcrops and seismic data, the dip angles of the faults and fractures are mostly greater than 400 and their azimuths are mentioned in study of Tran L.D. et al (2006). There are five main fault and fracture systems found in the Cuu Long basin and neighbor areas:

- The NE fault system, found in both onshore and offshore with azimuth 30-550,

- The NW fault system, azimuth of 310-3350 in onshore and about 300-3100 in several blocks in offshore,

- The EW fault system with azimuth of 75-950,

- The NS fault system with azimuth of 5-150, and

- The NWW fault system, with azimuth of 280-3100.

Three systems developed with the highest density are NE, EW, and NW systems. The NE system has a very high density in the offshore area. This system is important for contributing porosity of reservoir.

Fracture development

In the history of geological structural development, authors have presented the stages which fractures and faults were formed in Vietnam’s continental shelf. Especially, in the tectonic study of the Cuu Long basin the Oligocene – Early Miocene stage controlled mainly fractures in the basement rocks and oil traps. And then, Middle-Late Miocene reversion tectonic accumulated oil in the fractures basement. Next, Pliocene-Quaternary stage formed the paths for oil connectivity and redistributed fractures in the basement rock reservoir (Do V.L. et al, 2008).

Reservoir Properties and Experiences

The basement granite rock reservoir of WT oil field can present a good reservoir because of the high fracture in the uplifted block. The oil was generated in the younger sedimentary rock, then migrated and accumulated in the basement rock during the post Oligocene tectonic movements (Nguyen T.T. et al, 2008; figure 8).

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Figure 8. Macrofracture and micropore in the basement reservoir (after Trinh, 2007 and Phan and Pham, 2008)

By lab and field studies, the igneous rock reservoirs contain small amount of porosity, which was formed by cooling magma (primary porosity), and a large amount of porosity (secondary porosity), which was formed by tectonic activities (fracture, joint and fault) and solution (vugs). Moreover, Nguyen and colleagues (2008) identified that the pore structure of the granite basement rock in the Cuu Long basin are characterized by high heterogeneity and complexity. Those pores are the result of various processes such as heat shrinkage and expansion of magmatic bodies, tectonic movements, hydrothermal impacts and weathering. The porosity range from 2% to 5% represents a good reservoir quality. In a study of Phung D.H. et al (2008), the porosity of the Dragon oil field fluctuated in a range from 0.22% to 15.04%, average 2.87%, which were measured by core plugs analysis and log and 1.48% by thin section.

Moreover in the White Tiger field, the porosities were studies and proven that two main types are macrofractures and microfractures (figure 8). Vietsovpetro has constructed the reservoir model with a macrofracture model for parallel oriented big fractures formed by tectonic destructions (contribute the media to flow fluid) and microfracture model for smaller fracture which alongside the above big fracture and vugs (Hoang V.Q., 2008; Hoang V.Q. et al, 2008; Nguyen T.T. et al, 2008).

From studies, the secondary porosities are more important than fracture porosity in basement rock reservoirs. However, these pores have been decreased with the depth and decreased from central block to the flange.

Additionally, the studies of permeability distribution of the White Tiger basement reservoir showed that the high permeable zones with high production rate relative to reserve faults. That mean zones near the normal faults have permeability lower than one near reverse faults (Tran D.L., 2008). This helps exploration geologist on searching oil reservoir faster.

In the White Tiger basement reservoir, the initial pressure was recorded at the absolute depth of -3650m is 41.7 mPa. The results of hydrodynamic investigations show that the whole reservoir is characterized by the united hydrodynamic system. There is no bottom water in this reservoir. However, water oil contact was found at depth of 2925m in the Dragon oil field with an initial pressure of 28.1 mPa and lower than one of the White Tiger field.

Figure 9. Pore space structure in White Tiger basement reservoir (Hoang V.Q. et al, 2008)

To maintain the reservoir pressure and increase oil recovery, water injection was applied in the basement WT reservoir. That was a successful application in that more than 100 millions tons of oil and tens of billions cubic meters of gas were recovered.

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Approach to Improved Oil Recovery from Basement Reservoir A large number of EOR research proposal in naturally fractured basemenet reservoir have been reported since early of 20th century. Field projects showed the technological capability to increase oil recovery and the estimated long run costs for their operation. This increase in oil recovery would directly result in addtinonal reserves extending the productive life of the different assets. This part presents an overview of EOR field experiences in the basement reservoir, an analysis of recent efforts and discusses briefly on new opportunities for novel chemical methods.

Prospects about oil production status of basement fields in the world

La Paz field, the first naturally basement reservoir was discovered before 1950 in Venezuala by accident. For the first time, people produced from Cretaceous limestone. And then oil was incidentaly discovered when they drill into basements rock. The exploration of oil reservoirs in the basement rock significantly increased from 1950s until now. Many basement reservoirs had been found in Libya and Algeria, Venezuela, US, Morocco, Brazil, Lybia, Algeria, Egypt and Russia. Most of those reservoirs had low production rates like 20 bbl/day at Orth field, 55 bbl/day at Beaver in the US and 210-756 bbl/day at Xinlongtai field, China. However, White Tiger in Viet Nam had the flow rate of over 3600 barrells oi per day (at 38/64” choke size and testing interval at depth of 3495-3502 mTVDss from exporation well BH-6) (Tran N. Canh., 2008). The production from the granite basement reservoirs has contributed more and more important in the total oil production in the White Tiger oil field, which is shown in Table 1. Therefore, White Tiger could be considered one of the biggest basement fileds of the world.

Table1: Report of Acummulative Oil Production in White Tiger Field (from Tran N. C, 2008) Year 1988 1992 1997 2002 2007

Accumulated crude production from fractured granite basement reservoirs 0.05 11.81 45.8 109.35 175.86

Accumulated crude production from other reservoirs 0.96 2.88 8.68 22.60 46.00

Total accumulated crude production 1.01 14.68 54.48 131.96 221.86

Percentage of basement production/total accumulated crude production 4.9 80.4 84.1 82.9 79.3

The maximum oil production in the basement reservoir was reached in 2002 (6.7 % of initially recoverable reserves), and the production capacity has been kept stability in 5 years from 1999 to 2003. However, after White Tiger reached the peak of production and it is gone to declining period. Many solutions were proposed to increase oil production in this mature field including:

Acid injection and bottomhole cleaning.

Hydraulic fracturing in combination with injection of substance for filling fractures.

Chemical flooding such as surfactant flooding, polymer flooding and periodical water injection.

Hydraulic propped fracturing

This method was proposed by some researchers in the Research and Design Institute of Vietsovpetro including S. Jain et al., 2007 and Duong D. L et al., 2008. This paper briefly introduces the efficiency to improve hydraulic propped fracturing in basement reservoir. Many previous researches reported an application of hydraulic fracturing treatments and acid fracturing treatments in naturally fractured carbonate reservoirs or sandstones formation. However, there is a limitation successful hydraulic or acid propped fracturing in deep, high temperature or vuggy-fractured granite basement reservoir. The main reasons could be explained due to: (1) excessive fluid leak-off nature into vuggy-fracture networks; (2) technical inadequacy on fracturing fluid requirements such as: compatibility of fluid and rock formation, controlled viscosity requirements, friction pressure and non damaging fluid loss control; (3) a availability with fracture geometry model for design and analysis; and (4) a lack of research and development in relation to economics (Duong D. L., 2008). Vietsovpetro applied hydraulic first time for 1 well which was produced in basement reservoir in 1995. The result is the well’s productivity increased 2.5 times to pre-treatment production record. Since 1992, Vietsovpetro and their service contractors have been performed over 186 treatments in basement reservoirs of the White Tiger field. The tempetrature in basement of the White Tiger field reservoir is usually more than 1400C, thus one of the most common methods is using acid oil emulsion. However, after many repeated acid treatments in every well and high temperature, this method is no longer effective. In additional, most of fractures and microfractures near wellbore had tended to closed with decreasing of average reservoir pressure. It makes more difficult for

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stimulation jobs and hydraulic fracturing become the most promising method to increase oil recovery. Figure 10 showed the typical setup scheme on a vessel for hydraulic fracturing.

Figure 10. Vessel Setup (from Duong D. L et al, 2008)

The design for hydraulic fracturing in basement the White Tiger field is described in Table 2.

Table 2. Design of hydraulic fracturing solution (from Duong D. L et al, 2008)

Fracturing Fluid Zirconate C/S-Linked. Polymeric Fluid YF550HT

Rheology 110 cP at 170 sec-1 and 3000F

Fluid loss 0.003 – 0.005 ft/min1/2 in.

Polymer Clean-up Combination of encapsulated and live breaker

Proppant High Strength Proppant CarboHSP* 16/20

In the main treatment process, they pumped a fluid slug at flow rate of 20-25 bpm and maximum proppant concentration of 8-9 PPA. About 60,000 to 80,000 lbs proppant is used per treatment and the treatment volume is approximately 1500 bbls. One historical case was shown on figure 12 with information of perforation intervals and production history of tested well. The flow rate in pre-treatment was 81 tons per day and after hydraulic fracturing the PI improved from 1.19 to 2.86 ton/day/bar. The effective period after fracturing treatment was 3 years and total added oil is 617000 bbls.

a. Wellbore design of well in White tiger field b. Production history of tested well in White Tiger field

Figure 11. Wellbore and production history of tested well (from Duong D. Let al, 2008)

This is one of successful case of improved oil recovery in the basement reservoirs by hydraulic fracturing. However, propped fracturing in naturally fracturing granite is a big challenge because of: excessive fluid loss in the naturally fractures open-hole during pumping might cause pre-mature screen out, high pump horse power for the long and, openhole section and multiple fraction initiation and propagation in the open-hole (Figure 12).

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Figure 12. Hydraulic fracturing in basement reservoir (from Duong D. L. et al, 2008)

Surfactant Flooding for high temperature, high salinity reservoirs

Surfactant plays an important role in oil recovery by reducing the interfacial tension between the injection brine and the residual oil. It can also alter the wettability of the formation in order to increase the oil recovery. However, high temperature and high salinity are big challenges in applying surfactant flooding in basement reservoirs. Le Kim Hung et al., 2008 have done some experiments and proposed one kind of surfactant that is fairly thermostable at 1500C and tolerate in conditions which have high total dissolved solids and high divalent cation in White Tiger oil field. This surfactant can reduce interfical tension between oil and water into 0.22 mN/m at low concentrations (0.1%). Also important in this surfactant is ability to remain low IFT values while aging surfactant solutions at 1500C for 31 days. These authors found the critical micelle concentration (CMC) by measuring the IFT of each surfactant at varied concentration. The result is shown in Table 3.

Table 3. Test of CMC determination (from Le K. H et al, 2008) Surfactant CMC, % IFT, dynes/cm

AS1 (in dist. Water) 0.2 0.08

AS2 0.014 0.7

AS3 0.024 0.4

From experimental results, AS1 had the lowest IFT but it was insoluble (maximum 0.01%) and formed precipitation in high salinity brine. CMC is the minimum concentration at which surfactant molecules begin to form micellaes. It is very important in surfactant flooding, and AS2 has the lower CMC than AS3 and AS1; thus AS2 seems more economical than others for field application due to less of chemical requirement. The results of compatibility and thermostability tests of the individual surfactant during 31 days of aging time are shown in Table 4.

Table 4. Surfactant Aging Time (from Le K. H et al, 2008)

Surfactant AS1 (0.01%) AS2 (0.1%) AS3 (0.1%)

Aging time, day

Appearance IFT, mN/m Appearance IFT, mN/m Appearance IFT, mN/m

0 Clear 4.45 Clear 0.7 Clear 0.4

7 Cloudy 5.19 Clear 0.92 Clear 0.43

14 Cloudy 6.31 Clear 1.61 Clear 0.49

21 Cloudy 7.79 Cloudy - Clear 0.51

31 Cloudy 11.13 Cloudy - Clear 0.53

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These authors mixed two surfactant solutions at 1500C for 14days to test the stability in reserevoir conditions. The results are shown in Table 5.

They also investigated the effects of pH on surfactant mixture hydrolysis in the experimental. They changed pH of surfactant solution during aging at 1500C. There are 2 systems were used in the experimental including (1) the first system: AS1 0.01%/AS3 0.09%/EGBE 0.05%; and the second system: AS4 0.01%/AS3 0.01%/EGBE 0.05%. And finally, an optimum surfactant composition was proposed in Table 6. This surfactant not only can reduce the IFT between oil and water but also prove stable in high temperature and high salinity.

Table 5. IFTs of Surfactant mixtures at various mixing ratios (From Le K. H, et al 2008)

AS1: AS2 RATIO

INITIAL IFT AFTER 14DAYS

IFT, mN/m Remark IFT, mN/m Remark

1:4 0.65 Clear - Cloudy

1:3 1.47 Clear - Cloudy

2:3 0.36 Clear - Cloudy

1:1 0.34 Clear - Cloudy

3:2 - Cloudy - Cloudy

3:1 - Cloudy - Cloudy

AS1: AS2 Ratio

Initial IFT after 14days

IFT, mN/m Remark IFT, mN/m Remark

1:9 0.26 Clear 0.29 Clear

1:7 0.28 Clear 0.31 Clear

1:6 0.19 Clear - Cloudy

1:5 0.17 Clear - Cloudy

1:4 - Cloudy - Cloudy

1:3 - Cloudy - Cloudy

AS1: AS2 Ratio

Initial IFT after 14days

IFT, mN/m Remark IFT, mN/m Remark

1:4 0.33 Clear - Cloudy

1:3 0.35 Clear - Cloudy

2:3 0.27 Clear - Cloudy

1:1 3.34 Clear - Cloudy

3:2 0.39 Clear - Cloudy

3:1 0.36 Clear - Cloudy

Table 6. Optimum surfactant composition (from Le K. H, et al 2008) Compositions of the surfactant mixture

AS4 AS3 EGBE

Mass, %wt Content, % Mass, %wt Content, % Mass, %wt Content, %

0.01 6.67 0.09 60.00 0.05 33.33

Water shut-off in Basement Reservoir

Case Study in Field Scale

After a long production time, the greatest difficulty regarding the White Tiger field is the high water level in the production well. Oil production from some wells in the White Tiger field has been impaired by excessive water production. Excess water

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not only reduced the artificaial lift efficiency but also imposed a great deal of damage to the oil zones. Some researches were done to solve this problem.

In 2002, Keng Seng Chan et al proposed a method to improve production water shutoff for the White Tiger field. This research was cooperated between Vietsovpetro and Schlumberger Well Services. In this study, the authors evaluated the potential of a high temperature polymer base water shut-off fluid for deep penetration of the fissure formation and a micro-fine cement system for sealing off the water entires. In 2005, the treatments were performed in 2 wells in the White Tiger basement reservoir for both tubing and without isolation packers. Two wells had 6.5” open-hole size, at approximately 4200 meter TD and 1500C reservoir temperature. The water cut was 95% in one well and 98% in other. They have done a series of experiments in the laboratory in order to screen and evaluate the possibility of water shut-off fluid systems in the fractured reservoir. Test results showed that the gels were excellent in terms of gellation time control and long-term thermal stability (Figure 13), but failed to fulfill VSP’s requirement on shear stress test right after pumping.

a. b. Figure 13. Polymer-Gel Preparation for Water Shut-off (a) and gel strength behavior vs. time (b), (from Keng Seng Chan. et al, 2006)

They found a new micro-fine particle system was the proposed for the near well bore seal right after the placement of the “flowing gel” in the formation. This system is a cementitious material specifically designed to more efficiently penetrate narrow gaps without bridging, or dehydrating during placement. Subsequent laboratory tests showed that this new system could be injected twice as efficiently as other micro-cements into narrow slots.

Their treatment for water shut-off in the basement, shown in Figure 15, was described as follows:

Identify main water entires by running a production logging tool before the treatment.

“Pin-point” WSO polymer fluid injection using a straddle type in flatable packer.

Cement squeeze with a microfine cement system to seal the treatment interval in near wellbore.

Pumping a protective fluid (water) from the annlulus to mitigate gel movement upward in the reservoir.

Figure 15. Water Shut-off Treatment (from Keng Seng Chan. et al, 2006)

Method 1: The successful key for the treatment preparation is determining a reliable zonal isolation tool for ensuring “Pin-Point” polymer gel injection. The first well was applied by this method after 2 years preparation. This was an openhole completion well, and they assumed that the excessive water inflow was from the two intervals 4168m – 4175m and 4158 – 4160m at the bottom of the well. The post-treatment followed the steps below:

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Place a conventional cement plug from bottom of well to 4180m

Set an inflatable packer at 4150m

Perform injectivity test

Mix and pump microfine cement slurry into the zones 4168m-4175m and 4158m – 4160m.

Method 2: After post treatment production, there was no change in production and the water-cut remained high at 95%. The other objective was shut-off water in the second well at the interval from 4046m to 4055m with the flowing fissure gel followed by the microfine cement in well B. The penetration depth of the water shut-off gel was 20m. The post-treatment includes:

Set the inflatable packer #1 at 4064m

Perform injectivity test. Pump conventional cement below packer #1

Set the inflatable packer #2 at 4000m

Perfom injectivity test. Pump the polymer gel into the target interval 4046m-4055m

Mix and pump 13 bbls of microfine cement

Disconect from packer. Place a cement plug on top of packer

After 2 weeks, the following procedures were done continuously:

Polymer gel injection will have to be made through production tubing without any packer

A dual injection method will be used which again involving pumping seawater from the annulus to suppress gel movement upward in the reservoir.

VSP Wireline was to run the PLT to determine flow distribution profile

Correlation between gel and seawater pumping rate as a funcetion of gel cumulative volume pumped was to be established using the PLT data, specifically for well B down-hole condition.

The results showed that water cut in the second well deceased from 98% to 92% and the total liquid inflow rates proor to and after the treatment were 400 m3/D and 480m3/D. Therefore, the WSO treatment in well B gained an additional oil production of 30.4m3/D or about 190 BOPD.

Case Study in Lab Scale

From the experience in the operated period, other chemico-physical action methods such as gas injection, alkaline injection, and surfactant injection are not suitable with the high temperature and extremely heterogeneous reservoir. It is necesary to study a special chemical to tolerate with reservoir conditions. Nguyen Phuong Tung et al proposed a polymer gel for water treatment in the White Tiger field. They used polyacrylamide gels crosslinked by multivalent ions such as Cr3+ and Al3+. The commercial PA and modified PA were obtained from the Ciba Company and the crosslinked agent is chromium acetate from Aldrich. Sea water was taken from the White Tiger field under the following conditions: pH 7.18; salinity 3.38%. Gels were prepared in vials 12 cm in heigh and 1.8 cm in inner diameter by combining Cr3+ and dilute by sea water. Solutions were then transferred into thermostable ampoules, freed oxygen, sealed and put into the oven at a counted temperature. The results of bottle testing are shown in Table 7 and 8 at 850C and 1150C.

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Table 7. Polymer Gelation at 850C (from Nguyen P. T et al, 2001) Sample 1 2 3

Cr3+ (ppm) 1500 1500 1500 Lactate (ppm) 12000 18000 24000 Gelation time 1.1 1.2 1.3

0 (hours) A A A 1 A A A 2 G A A 3 I F A 4 I H C 6 I I D 8 I I D

24 I I F 30 I I F

2 days I I I 1 week I I I 2 weeks I I I 3 weeks I I I 4 weeks I I I 5 weeks I I I 6 weeks I I I 7 weeks I I I

Table 8. Polymer Gelation at 1150C (from Nguyen P. T et al, 2001) Sample 1 2 3

Cr3+ (ppm) 1500 1500 1500 Lactate (ppm) 12000 18000 24000 Gelation time 2.1 2.2 2.3

0 (hours) A A A 1 A A A 2 H B A 3 I F B 4 I H C 6 I I D 8 I I D

24 I I F 30 I I F

2 days I I I 1 week SYN I I 2 weeks I I 3 weeks SYN I 4 weeks I 5 weeks I 6 weeks I 7 weeks I

Conclusion Having studied a great deal of literature researches and papers regarding the basement reservoir of the Cuu Long basin, the authors conclude the following main points:

1. The granite basement rock can be a good reservoir at the uplifted blocks in the center and margins of the basin in which contain many fracture and fault due to a variety of processes such as tectonic movements, hydrothermal alteration and the weathering processes.

2. The distribution of porosity is near the top of basement and faults. The fracture porosity decreases with increasing depth.

3. The discovery of oil in the granite basement rock opened for exploration in the other oil fields and basins in continental shelf of Vietnam, even in the adjacent basins with containing granite basement rock as White Tiger and Dragon oil field.

4. In the naturally fractured basement reservoir, it is a challenge to apply enhanced oil recovery due to the complexity of geological characterization. However, some EOR applications were successfully performed for both lab and field scales. This is really a worthwhile lesson to the improvement of the efficiency of the EOR process for different basement reservoirs in the world.

IPTC 13577 15

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