Completion Strategy: A Case Study of Using Autonomous Inflow Control Technology to Manage Water

Abstract

The issue of high-water cut will have repercussions for every oil operator on the planet. The presence of scales, corrosion, and deterioration, along with the expense of separation, are all exacerbated by an overabundance of water production, driving up the price of lifting fluids. To understand the challenges faced by the many wells there, data from one of the offshore oil fields had to be analyzed. The autonomous inflow control valves (AICVs) method is used for water control in different reservoirs. Swell packers are used in the AICV method to permanently seal off the well. Additionally, the completion strategy for handling the high-water cut has been outlined. It also discusses the availability of many inflow control systems for well completion to stop undesired water production, as well as the efficacy of various water shut-off techniques. The study offers a complete approach for water control in horizontal wells for the future rehabilitation plan of the Offshore Field by analyzing the effectiveness of these technologies via a variety of case studies and literature research. After analyzing the reservoir and fluid properties of the western offshore field, a completion strategy was suggested for the future redevelopment plan.

1. Introduction

To prolong the period the wellbore is in direct contact with the reservoir, horizontal wells are increasingly being drilled. Horizontal wells are a good alternative to vertical wells when they are not available or when a corporation wants to reduce the number of vertical wells [1]. These are occasionally drilled to increase the area of contact with the pay zones or to access targets buried beneath nearby strata. Due to the angle at which these horizontal wells are dug, a variety of problems that could lower production rates are more likely to affect them. An existing heterogeneous well’s level of heterogeneity is influenced by fractures, solution channels, near-water zones, high permeability zones, fractures connecting water aquifers, heterogeneous oil-water contact, and heterogeneous permeability [2]. Poor oil output, drastically declining rates of oil production, and a shorter economic production life for the well are the results of this non-uniform flow sweep in the wellbore [3, 4, 5].

The issue of high-water cut will have repercussions for every oil operator on the planet. This occurs in both older and more recently constructed wells [6]. Many factories feel the effects of this in their bottom lines. The presence of scales, corrosion, and deterioration, along with the expense of separation, are all exacerbated by an overabundance of water production, driving up the price of lifting fluids. Production well efficiency and lifespan are both negatively impacted. Therefore, it is vital to resolve water shortage concerns. Therefore, knowing the formation and field inside and out during wellbore design [7, 8, 9, 10, 11] can help to cut down on water output that is not needed.

There is hardly one cookie-cutter answer to any problem. It is necessary to comprehend the nature of the issue to correctly address a given water scenario. There are several approaches to handle high-water cuttings [12]. The mechanical and chemical processes are two examples. During mechanical water shut-off procedures, expandable and non-expandable packers are used to isolate the wellbore’s water-producing parts. Only a few examples of chemical techniques include in situ gels, polymer and swelling agents, water swelling polymers, Micro Matrix Cement, and HWSO plugging agents. These are applied in different ways depending on the specifics of the well’s water level-lowering problem. There are a lot of potential answers to the issue of wasteful water production, but it is difficult to put these solutions into practice and successfully reduce water consumption [4, 13, 14, 15, 16, 17, 18, 19].

Engineers investigated the problem of water cuts at a functioning oil field in the Indian Western Offshore Basin (WOB) in this study. In 1985, it was determined that the area was a field. In addition to three gas caps, the field has a reasonably reliable bottom aquifer. The field has a reserve of 42.54 MMT and an estimated OIIP of 112.48 MMT. Water injections started in July 1994, and initial production started in March 1990. With an average water cut of 90%, the field is now injecting water at a rate of 85,000 BWPD and producing oil at a rate of 14,400 BPD. The field had produced 35.54 MMT (31.6% OIIP) as of March 2019. Both newly drilled and side-tracked wells as well as older wells have experienced a sharp increase in the ratio of water to oil production (W/C).

2. Geological setup

The field is crescent-shaped, with two summits separated by a mild saddle and a shared OWC at 1477 m. Tectonic activities linked with fault reactivation have most likely resulted in significant fracture of carbonate rocks. The crack has likely caused karstification by acting as a conduit/pathway for the movement of meteoric water. Core investigations have shown three types of diagnostic traits in reservoir development.

Zone of Intense Karstification: This is the highest zone of Bassein pay. The formation of vugs, solution channels, and collapse breccia on this face indicate significant Karstification in the meteoric zone.

Tight Zone: Sparitization is abundant in the tight zone under the severely karstified zone. There are several types of fractures. Fractures, vugs, and faunal chambers from earlier generations are mainly sparitized, contributing to a reduction in porosity.

Changed Limestone: This zone is very permeable and mostly composed of altered chalky limestone. Because of the breakdown of lime mud, it forms microporosity.

3. Problems with offshore field’s water cut and well treatments applied

The field began production in March 1990 through four wells of the P-1 platform beginning in 1993–1994. In 1993–1994, the field had a peak oil output of around 95,000 BOPD. In July 1994, as shown in Figure 1, water injection began from the W-1 and W-2 platforms in the field’s southernmost section. Despite beginning in April 1994, water reduction increased steadily until it reached 66% in 1999. The rise in water cut was not consistent over the field because of the field’s highly varied aerial and vertical structure. Oil is produced from the naturally fractured carbonate reservoir found in the field known as Bassein pay. There are karstified zones, solution channels, cracks, and vugs in this reservoir. This issue has always been a source of mud leaks and water injection failures. From 1994 to 1998, the water cut in the field increased by a factor of 40, and from 1998 to 2002, it increased by another 60–70. Numerous factors, including the presence of fractures, wormholes, channeling from injectors and aquifer, completion in the water zone, high permeability variation, water coning, and so on, have contributed to the field’s current extremely high water output. From no water reduction in 1994 to a 70% reduction in 2002, the field is now facing a situation where more than 90% of the water used in production must be conserved. There are a total of 92 oil-producing wells in this western offshore area, 71 of which use horizontal wells with slotted tubing and 21 of which are vertical or inclined. These oil-producing wells, which include horizontal wells, have had over 90% of the water removed and are back to normal operation. Horizontal wells may use slotted or perforated tubing as a final touch, making it difficult to trace the water’s origin [20].

Figure 1.

Production-injection performance of the Western offshore field.

The water cut worries are greater in the northern half of the field, where the thickness is only 15–20 m than in the southern part of the field, where the thickness is 50–100 m (70 m). Due to thickness differences and inherent unpredictability, some areas recovered more quickly than others. The average productivity of the northern sector is 0.036 MMt/string, whereas the combined productivity of the northern and southern sectors is 0.185 MMt/string. The field’s production and injection performance through time is depicted in the following graphs.

The asset routinely implemented corrective measures, such as chemical water shut-off works, to curb the output of water from horizontal wells that was deemed excessive. These procedures were conducted in conjunction with a number of institutions and other service providers in an effort to control the excessive output of water from horizontal wells. Chemical water shut-off activities were carried out in the field based on the Western Offshore Field’s geology and reservoir characteristics. The selection of appropriate water shut-off tasks was guided by geological factors, reservoir characteristics, fluid properties, and challenges encountered during water cuts. These decisions were substantiated through in-lab experiments and literature reviews. Because of the detrimental effects the excessive water production had, these procedures were shifted to horizontal wells with high-water cut concerns [21].

Polymer gel technology, more precisely “PHPA Polymer with Metallic Cross Linker” and “PHPA Polymer with Organic Cross Linker,” was employed for chemical water shut-off operations in the western offshore region. Water shut-off jobs utilizing this polymer gel technology in a large number of horizontal wells had promising early results, but the wells continued to produce a high-water cut after a few months due to an increase in field water cut and movement of water due to water coning and water breakthrough. The job done by chemical water shut-off in high-water cut wells is illustrated by the bar graphs below (Figures 2–5). It shows the production status of the well before and after the water was turned off.

Figure 2.

Performance of the wells pre-and post-WSO jobs.

Figure 3.

Performance of the wells pre-and post-WSO jobs.

Figure 4.

Performance of the wells pre-and post-WSO jobs.

Figure 5.

Performance of the wells pre-and post-WSO jobs.

Some success was had with using polymer gel water shut-off to address water cut difficulties in horizontal wells, however, these results were inconsistent. Eight of the 18 wells given the water shut-off job saw significant improvements in oil rates and water cut, three saw moderate gains, two saw none, and five saw no change in productivity. Wells that had no improvement in water cut difficulties after implementing polymer gel jobs were more likely to experience a high number of water cuts much sooner than other wells [22]. After a polymer gel was applied, the number of productive wells stayed rather constant (3–6 months). However, these readings did not last long, as water cuts increased at the wells in tandem with a drop in oil rates as a result of water coning and water breakthrough. The water cut in the field rose again after a certain length of time had passed, and this rise was in concert with an increase in water cut in these wells as a result of WSO jobs. Water cut cannot be controlled throughout a well’s life even if a successful water shut-off scheme is implemented at the beginning of the well’s life.

4. Completion strategy for different reservoir properties

A thorough understanding of reservoir parameters during drilling and logging can aid in the development of an effective water control completion strategy. Taking these reservoir qualities into account and applying the appropriate technique for those properties might assist delay and control water production. The following are some examples of completion strategies for various reservoir parameters.

Scenario 1: A horizontal wellbore completion approach for an unconsolidated sandstone formation with varied permeability. To control water in the future, a horizontal unconsolidated sandstone reservoir with the following features must be completed (Figure 6).

• Unconsolidated sandstone reservoir

• A long wellbore with near water aquifer support

• Presence of low-viscosity hydrocarbon in the formation

• A long and thin pay zone thickness with low permeability variation

• Reliability

• Limited hydrocarbon reserves and low flow rate

Figure 6.

Completion strategy for unconsolidated sandstone formation using ICDs.

According to the aforementioned reservoir features, adopting an inflow control device (ICD) will be the most appropriate strategy for effectively producing hydrocarbons while preventing the creation of undesirable water. To prevent wellbore collapse in an unconsolidated sandstone formation, the production formation must be cased, cemented, and perforated along the length of the horizontal wellbore. To finish a well with an ICD, the well must be segregated into sections with packers calculated by reservoir modeling and simulation software for the specific reservoir parameters [14, 23, 24].

The ability of the inflow regulate device to filter sand using screens before flowing into the device can effectively control the probability of increasing sand production from the unconsolidated sandstone deposit. Wells are less likely to experience early water breakthrough due to excessive water coning if fluid inflow is uniform from all directions, as is the case when using an ICD [25]. Thus, the ICD will ensure uniform inflow across the entire wellbore and suppress the production of water in areas close to the oil-water interface (Figure 6). ICDs will successfully create light oil by providing lower pressure drops for light oil zones and bigger pressure drops for heavy oil zones since they are ideally adapted to low-viscosity fluids. ICD would help overcome the well cost and give effective good production, making the well economical by equalizing the fluid flow along the wellbore length in the low permeability variation formation. The great reliability of channel-type ICDs in overcoming clogging and erosion could aid in the prevention.

of system failure [26]. The ICD is more capable of producing low flowrate fluid formations and including artificial lift in the form of gas lift to produce remaining reserves for maximum oil recovery in a well. As a result, based on the limited reserves in the well, ICDs will efficiently generate the most hydrocarbons, making the well profitable [27, 28, 29, 30].

Scenario 2: A horizontal wellbore completion approach for a cemented sandstone formation with varied permeability. A horizontal consolidated formation with the following qualities must be completed with a water-cut control method (Figure 7).

• High permeability variation wellbore

• A wellbore with a thin pay zone, high water aquifer support, and gas cap

• Presence of low-viscosity hydrocarbons in the formation

• Heterogeneous oil-water contact and near water zones

• Presence of some fractures connecting bottom water aquifer

Figure 7.

Completion strategy for consolidated sandstone formation using AICDs.

Depending on the aforementioned reservoir parameters, incorporating an AICD into the completion strategy will be the most efficient means of producing hydrocarbons. The above-mentioned cemented carbonate formation can be extracted via open-hole well completion from the well. Using reservoir data and wellbore modeling and simulator software, the number and location of autonomous inflow control devices (AICDs) and packers in the wellbore can be estimated, allowing for a successful completion with an AICD. Depending on the reservoir and fluid qualities, this will aid in the production of fluids from each zone of the wellbore [31, 32, 33, 34, 35]. The occurrence of considerable permeability variation along the wellbore can result in non-uniform production in wellbore zones. The AICD maintains productive wells by regulating oil and water flows independently. This can also assist minimize water coning at the well’s heel by lessening the “heel-toe effect” that happens in long wellbores. Perforated tubing can be used to complete zones with exceptionally low permeability, resulting in negligible pressure drop and efficient production. AICDs can sustain hydrocarbon displacement by the below heterogeneous oil-water contact along the horizontal wellbore by balancing the inflow throughout the wellbore. Producing hydrocarbons with varying viscosities is one of several applications for the autonomous ICD [36, 37, 38, 39, 40, 41].

AICDs are rate-dependent, along with fluid property identification, and provide effective light oil production, resulting in increased oil output while preventing the flow of undesirable fluids (Figure 7). Because of the AICD’s sensitivity, oil can generate and restrict water and gas, effectively regulating water cut and GOR [42]. Fractures are the primary source of variability that contributes to extremely high permeability zones. If connected to a water source, these zones may give very high hydrocarbon production and early water breakthrough. AICDs can successfully produce an extra pressure drop in these high permeability zones while managing wellbore input and preventing early water breakthrough. When AICDs achieve breakthrough, they can effectively limit water and gas production by imposing significant resistance to their flow while enabling oil to flow through the least resistance. AICDs aid water breakthrough from these zones by creating an equal amount of hydrocarbons across the wellbore.

Scenario 3: A completion technique for very heterogeneous carbonate formation with a wide range of K. To control future high-water output, a highly heterogeneous formation with the following features must be completed (Figure 8).

• A long wellbore with high permeability variation

• Presence of high viscosity hydrocarbon in the formation

• Heterogeneous oil-water contact with near water zones

• Presence of a gas cap in the formation along with high-water aquifer support

• Presence of high permeability fractures connecting the below water zones

Figure 8.

Completion strategy for highly heterogeneous carbonate formation using AICVs.

The production of cemented carbonates eliminates the problem of wellbore collapse. Because the formation is highly heterogeneous, the well should be completed utilizing effective zonal isolation by producing a well into segments. To maximize oil recovery while delaying or controlling water output, the optimal well completion strategy given the aforementioned reservoir characteristics is to employ autonomous inflow control valves (AICVs). By isolating each zone of the wellbore with packers determined by reservoir modeling and simulation software for the precise reservoir parameters, AICVs can be placed anywhere along the wellbore length to take advantage of various reservoir features. The zone contributing to very high permeability due to the existence of a large number of cracks can be totally segregated without the installation of AICV, resulting in early and very high-water production right from the start [43, 44].

The AICVs will create hydrocarbon in each segment of the wellbore with a homogeneous influx of fluids, ensuring consistent production across the whole length of the wellbore. In high permeability zones, autonomous inflow control valves will provide an extra pressure drop, permitting equal fluid flow in each segment of the wellbore [45]. It will also lessen the possibility of water coning in the lengthy wellbore due to the heel-toe phenomenon. AICVs are extremely effective in producing high-viscosity fluids (oil) by allowing low restrictions to their flow into the wellbore, while allowing low-viscosity fluids (water and gas) to flow through heavy restrictions and produce in negligible amounts. AICVs essentially allow high-viscosity fluids to flow freely while effectively shutting them down for low-viscosity fluids.

AICVs can fully shut down output from a zone when water breaks through from nearby water zones or moving oil-water contact occurs owing to heterogeneous oil-water contact (Figure 8). The existence of a gas cap contributing to high GOR can be controlled with AICV by turning off the operation and enabling oil in other zones to retain well productivity due to its applicability for shutting off production for low-viscosity fluids. AICV is the best device for shutting down production in a zone connected with a high-permeability fracture because it restricts the flow of water the most. Since water can acquire the entire wellbore section through high permeability cracks connecting the water aquifer, the AICVs successfully avoid these zones by shutting down production while preserving well productivity by producing through other zones [46, 47].

Scenario 4: Completion approach for very heterogeneous carbonate deposit with substantial permeability variation and high production fluids. To achieve optimum oil recovery and controlled water production, a highly heterogeneous formation with the following features must be finished (Figure 9).

• A highly heterogeneous formation with a high length and thick pay zone containing a very high amount of reserves

• There is considerable permeability variation in the formation and plentiful water aquifers

• There is the presence of low-viscosity oil.

• Presence of a large amount of high- and low-permeability fractures

• A gas cap formation and the need for artificial lift in future

Figure 9.

Completion strategy for highly heterogeneous carbonate formation using IWC.

Since the aforementioned formation is a cemented carbonate formation, an open hole well completion can be used to eliminate the possibility of hole collapse. Carbonate formations like this one require state-of-the-art intelligent well completion equipment due to its high reserves and complicated geology. It is necessary to partition the well into sub-sections according to the various requirements of the reservoir for the intelligent well completion system to function properly. This can assist in producing independently from each zone of the wellbore to balance the overall well output [48].

The surface-controlled inflow control valves will be the best choice for monitoring the behavior of each zone and controlling the valves based on the need to produce from that zone (Figure 9). Due to the limited installation downhole, an electrically driven inflow control valve would be the preferred choice to produce the big formation over hydraulic inflow control valves [49, 50]. This intelligent well completion can help to monitor reservoir and fluid parameters from each zone, as well as manage flow through varying openings in each zone. This will allow you to manually respond to changing behavior in each zone while remaining productive. The temperature, pressure, flow, and composition of fluid flowing in each zone are monitored by a sensor and transmitted to the surface analysis system, where the appropriate approach to the behavior is decided and controlled from the surface with the varying openings of the inflow control valves [51]. Using an intelligent well-completion system, controlling each zone based on its features would aid in recovering maximum reserves in a very heterogeneous formation [46, 52].

Indicators of the formation’s heterogeneity include the presence of both high- and low-permeability cracks and the presence of a wide range of permeability fluctuations. Intelligent good completion is autonomous in identifying fluid features because it is not automatic but rather is operated by carefully examining the fluid’s qualities. As a result, water and gas breakthroughs may be easily monitored by operators due to high permeability fractures or gas caps, and necessary actions are done by totally shutting off the valves while continuing to produce oil and other zones. Intelligent well completion enables artificial lift such as in-situ gas lift, gas lift, or ESP to recover maximum reserves from the formation in the future for the production of remaining reserves under low pressure.

An intelligent well completion system is an incredibly expensive system that can only be installed in formations with a large number of reserves existing, such as the above formation, where the well cost can be overcome and the end recovery results in a good profit, making the well profitable. The western offshore field is a highly heterogeneous cemented carbonate formation. It has a strong water aquifer support beneath the pay zone and a gas cap. Its remarkable heterogeneity is dominated by cracks, vugs, and solution channels. Water can easily flow from the aquifer to the wellbore as a result of these fissures, some of which are connected to the bottom water aquifer support. Because of water coning in the adjacent water zones and close to the oil-water interface, water breakthrough occurs early. The northern part of the field is thinner, making the well more susceptible to water coning (15–20 m).

Oil-water contact is consistent across the field, with a common oil-water contact at 1477 m in both the northern and southern portions. Permeability changes dramatically along the field’s length due to significant variability. A reservoir pressure of 2000 to 2500 psi and a temperature of 100 to 120°C are typical in this field. The carbonate deposit has a permeability range of 1–500 millidarcy and a porosity range of 15–25%. In comparison to the formation water, the oil in this deposit has a low API gravity of about 35 to 42°C. In reservoir circumstances, oil has a viscosity of 0.9 cP, formation water is 0.4 cP, and gas has a viscosity of 0.02 cP. The field’s initial oil in situ is expected to be 112.48 MMT, with final reserves of 42.54 MMT. 35.54 MMT (31.6 OIIP) of which has been generated. A redevelopment plan is being implemented, with 9 additional wells being added to the current 92 wells in order to collect the remaining reserves from the field.

According to literature research [6, 7, 12, 13, 20, 21, 22] examining reservoir characteristics and water cut issues that are similar to the Western Offshore Field, AICD is the best completion method for reducing water cut. Using swell packers to permanently seal off the well is a crucial aspect of the completion technique when implementing AICD. By separating the well into sectors using zonal isolation and installing AICD in each sector, it is possible to generate a homogeneous influx along the horizontal wellbore. Optimizing the placement and number of swell packers and AICDs can be done by modeling the well with a NETool or Static Simulator Software and comparing input numbers from other wells or drilling and logging data. The highly diverse Western Offshore Field can now maximize oil production with the aid of AICD by effectively preventing and controlling water breakthrough. High permeability zones can contribute to an unbalanced input of fluids along the wellbore’s length, however, AICD will effectively restrict their flow [53]. If fluids are constantly moving down the wellbore, water is less likely to condense in high-permeability areas and rush out the well before it is ready. Careful input management [54, 55] can reduce the possibility of an early water breakthrough caused by the displacement of water from neighboring water zones and close oil-water interaction.

Due to the formation’s high heterogeneity caused by the presence of fractures, vugs, and solution channels, it is crucial to regulate inflow to prevent fluids from these conduits from dominating the flow into the wellbore and limiting flow from other zones. AICD will be able to control the flow from these pipes and maintain a steady flow of water into the well [56]. If these pipes are connected to a water supply, water will flow through them instead of oil, making a breakthrough nearly impossible to prevent. The development of AICD will permit oil and water to be efficiently managed together. Water going through AICD will be severely limited due to its oblique path around the output, but oil will encounter fewer restrictions thanks to its radial flow pattern. AICD will lead to increased oil production and better gas output regulation. This thin oil rim deposit has a stable water aquifer and a gas cap that regulates the amount of water and gas that can be taken, making it a good candidate for hydrocarbon extraction using AICD. With AICD, the input across the wellbore will be managed to avoid premature water breakthrough in the very heterogeneous Western Offshore Field formation, and after water breakthrough has occurred, AICD will efficiently control water production to ensure maximum oil recovery.

Engineers determined that a Range 1 Fluidic Diode AICD would be the most effective ICD for the Western Offshore Field due to fluid characteristics being similar to Completion Strategy Case 2. When AICD detects certain fluid qualities, it is able to shut off the water supply. The temperature of all the oil in the field is between 35°C and 42°C on the API scale, and its viscosity is only 0.9 cP. Additionally, the viscosity difference between field oil (0.9 cP) and water is rather small (0.4 cP). The AICD (0.3–1.5 cP) Range 1 Fluidic Diode type excels for making light oil and identifying the minute differences between fluids. If the tiny difference in viscosity between light oil and water can be determined [57], then AICDs of the Range 1 Fluidic Diode type can be utilized to restrict water flow and boost oil output. AICD’s ability to stabilize input is especially helpful in regions where permeability fluctuates significantly (more than 0.1 mD but less than 500 mD). Therefore, the completion technique using a Range 1 Fluidic Diode type AICD and Zonal Isolation was more appropriate for the Western Offshore Field. To this end, it was planned to implement a completion approach wherein the wells involved in the field’s rehabilitation plan would have AICDs of the Range 1 Fluidic Diode type installed with Zonal Isolation.

Two newly side-tracked wells were completed in accordance with the AICD Completion Strategy as part of the Field Redevelopment Program and began production in August 2021. Placement and quantity of packers and AICDs installed were determined by NETool software modeling of a well, and zonal isolation was achieved by using swell packers and AICDs of the Range 1 Fluidic Diode type (0.3–1.5 cP).

When the production performance of these wells was analyzed, the wells performed similarly to other wells (without an Inflow Control System) in the initial phase of production, with 6 and 11% of water cut. However, after 9 months of operation, the water cut of these wells climbed to 38 and 47%, respectively, when compared to other wells where a steady increase in water cut was noted (Figure 10). The other wells achieved greater than 80% water cut within 4–5 months after going into production. When compared to other wells, the wells finished with a Completion Strategy performed exceptionally well in terms of limiting the water cut and producing adequate amounts of hydrocarbon, thereby recovering the residual hydrocarbon efficiently. The Completion Strategy performed admirably, as expected, with Zonal Isolation using swell packers producing hydrocarbons from each zone specifically to maintain uniform oil production across the wellbore, whereas AICDs assisted in producing high amounts of hydrocarbons and effectively controlling water production. The best solution to manage the water cut issue was found to be completing the wells as part of the Field Redevelopment Program using a Completion Strategy that included Zonal Isolation with Swell Packers and Range 1 Fluidic Diode type AICD (0.3–1.5 cP).

Figure 10.

Completion strategy for initial flow rate vs. post flow rate.

5. Results and discussion

Water’s low viscosity allows it to flow through oil and into the entire wellbore section, and this phenomenon, known as water cut, is shown to worsen with time once it has established itself in a well. This was uncovered after an exhaustive study of the finished Western Offshore Field and an appreciation of the multiple water shut-off jobs utilized to regulate water output revealed the truth. Since water can flow through any channel connecting the wellbore when water cut problem arises, it is very challenging to regulate water production. Water shut-off can be accomplished in a number of ways, both mechanically and chemically. Most methods of water shut-off used to lessen the severity of water shortage worries are not particularly effective, and they cannot be relied upon to halt water output for long [58]. Water shut-off techniques can only limit the water cut to a certain level for a few period of time before the well starts producing an enhanced volume of water. This is because halting water in a highly permeable heterogeneous field is particularly tough. As a whole, it is rather challenging to manage the water once it has begun to flow, which makes the goods costly and the well uneconomical. Rather than relying on reactive methods to regulate future water production, this method takes preventative action throughout a well’s lifetime. Using modern inflow control systems, such as ICDs, AICDs, ICVs, AICVs, and intelligent wells, in conjunction with zonal isolation based on reservoir properties, can prevent uncontrolled production and water breakthrough. This method of well finishing can help increase the well’s profitability by increasing its useful life, decreasing the need for well intervention, increasing hydrocarbon production, and decreasing water production. In addition, the chapter provides several illustrations of various reservoir characteristics with suitable completion processes for regulating water production.

6. Conclusion

Since unwanted water reduces production from the flowing well and raises operational expenses for water management, corrosion of subsurface and surface equipment, pipeline, etc., it is one of the biggest difficulties for an Exploration and Creation company. The efficiency of a well is directly affected by any water that is leaking out of it. Once water cut issues in the form of work over activities emerge, a number of mechanical and chemical remedies are available for halting undesired water production. However, these systems are incapable of effectively shutting down water production, and the possibilities of successfully applying this option are similarly slim.

• To identify problems and find solutions for decreasing water cut and increasing field output, we examined well-by-well production and injection behavior using a variety of classical plots; analyzed pre-existing in-house water shut-off methods (both mechanical and chemical); and investigated global technologies.

• Studies of the Indian Western Offshore Field, its water cut issues, and the various water shut-off methods implemented in its wells, as well as several water shut-off case studies, revealed that: It is difficult, ineffective, and nearly impossible to increase the productivity of a well for a longer period of time by attempting to control water production after the fact. Mechanical and chemical water shut-off jobs are difficult to execute down hole, and even if they are, they only give temporary respite from water scarcity. Therefore, water shut-off solutions cannot ensure water cut mitigation.

• If a completion plan is developed to prevent and manage water output, it may be possible to avoid well intervention for water shut-off actions. The proper completion method will serve as an efficient water control measure even before the problem occurs, rather than applying for water shut-off work after the fact, which has a low success rate and is less effective. This technique can reduce water output by delaying the emergence of water breakthroughs in a well through the use of preventative measures. For one thing, it employs Zonal Isolation in tandem with a reservoir-specific Inflow Control System (ICD, AICD, ICVs, or AICVs).

• It recognizes water’s individual qualities and limits its flow to restrict its breakthrough output, whereas looser restrictions promote oil production. Early water breakthrough can be prevented with the help of an Inflow Control System and Zonal Isolation, which work together to equalize the inflow across the wellbore and then isolate the source of the water flow after it has broken through, all while keeping oil production at a steady rate.

• A completion strategy involving a Range 1 Fluidic Diode type AICD with Zonal Isolation utilizing Swell Packers was proposed to install in horizontal wells for the future redevelopment plan of the field after studying the reservoir and fluid properties of the Western Offshore Field with the issue of high-water cut. This finishing method can be created for deployment in a field’s wells to efficiently eliminate water cut problems and boost future wells’ productivity by utilizing simulator software to decide the placement and number of AICDs and Packers. Possible effects of this completion approach include a decrease in water production and an increase in cumulative oil output from the very heterogeneous western offshore field.

• Comprehensive completion plans are suggested for the future redevelopment of the field, which will involve drilling or side-tracking additional wells. It was agreed that Range 1 Fluidic Diode AICDs will be employed to complete subsequent wells. Two new side-tracked wells on the P-3 and P-4 Platforms were completed utilizing the completion technique of zonal isolation using swell packers and Range 1 Fluidic Diode type AICD (0.3–1.5 cP), resulting in excellent control over water cut and good hydrocarbon rates. As a result, the project of Completion Strategy for controlling water cut in the field was found to be successful, and it was agreed that future wells to be drilled and produced to recover the remaining hydrocarbons would be completed using the same Completion Strategy.

Acknowledgments

The authors are grateful to the Dr. Vishwanath Karad MIT World Peace University for providing us with all the facilities that were required work.