Jain, Bipin

This paper describes the process followed to explain the mechanical blockage in the flow path observed while displacing the cement slurries in long casing strings set with short rat holes. In most of the cases, those blockages ended with amount of cement left in pipe and significant remedial works.

All the incidents were investigated involving casing design experts, cementing specialists and data analysts to understand the root causes. Mud logging unit, cementing and rig sensors data from several cementing jobs were analyzed in an integrated and holistic approach. Four different software’s were used to simulate and prove the theory that total elongation of the casing was enough to exceed the rat hole length bringing the casing in contact with the bottom of the well, and therefore blocking the flow path.

In all the incidents, the issue was observed at the beginning of the slurry displacement stage where the entire volume of the cement was still inside the casing. Other possible causes of blockage (cement contamination, mechanical failures, loss control material,…) were also checked and ruled out.

Hookload data was available to be analyzed whenever a conventional wellhead was installed, and the casing was held on the elevators during the cementing job. However, in some cases this information was not available as a compact wellhead was used. For those cases, it was necessary to drill out the shoe track using LWD to detect the location of casing shoe.

Recommendations were made to add new loads the current casing design. Results will define the minimum rathole length and the maximum tension at surface experienced by the casing during the cementing job in both static and dynamic conditions. Also, it is important to properly estimate the rathole the physical measurement of the casing joints in the tally can carry measurement errors.

Lost circulation is a widespread problem in many formations in the United Arab Emirates, including Shallow Unconsolidated, Shallow Vuguler and Limestone. To minimize losses during drilling and cementing, several types of lost circulation solutions such as bridging agents and surface-mixed and downhole-mixed solutions have been used. Still, operators lose huge volumes of mud and cement slurry and expensive rig time. Consequently, many wells also require remedial operations, which can compromise well integrity.

Loss-zone diagnosis and characterization helped to tailor the loss-circulation control solution for different requirements. Losses can occur due to unconsolidated formation (surface holes) or induced and natural fractures. Typical loss rates can vary between 150 to over 700 bbl/hr, particularly while drilling the 16-in. and 12 ¼-in. openhole sections. Thus, total losses in shallow vuguler formation require a different treatment than induced losses in shallow unconsolidated or limestone formation. Induced losses in limestone while drilling prevented increase in mud weights required to drill deeper reactive shale formation. A composite fiber-based system based on a novel four-step methodology was designed using advanced software analysis. Prior to the field trial a complete lab-scale and yard-scale testing was done to confirm superior effectiveness.

In one of the pilot wells, multiple leakoff tests (LOTs) were performed in the Limestone formation to verify the minimum stress (1.40 SG), which did not change with subsequent LOTs. The formation was then treated with the reinforced composite mat based system, and the following formation LOT showed integrity buildup to 1.51 SG. It proved to be an easy to apply solution that can be mixed and pumped through a qualified bottomhole assembly (BHA).

Zone and mechanism specific lost circulation control solutions are most effective in reducing nonproductive time (NPT). It was also demonstrated that fiber-based solutions work well for controlling losses and formation strengthening. The engineered composite fiber-blend system exhibits improved performance and robustness in terms of curing losses and even improves formation integrity.

Achieving well integrity relies on achieving zonal isolation among narrowly separated sublayers of the reservoir throughout a long openhole section. This requires flawless primary cementation with a perfect match of optimized fluid design and placement.

In a UAE field, there are several challenges experienced while cementing production sections, predominantly due to long open holes with high deviation, use of nonaqueous fluids (NAF) for shale stability, and loss circulation issues while drilling and cementing. The need to pressure-test casing at high pressures after the cement is set and the change in downhole pressures and temperatures during well completion / production phases result in additional stresses that can further endanger the integrity of the cement. Breaking of the cement sheath would lead to sustained annular pressure and compromise the needed zonal isolation. Hence, the mechanical properties for cement systems must be thoroughly tested and tailored to withstand the downhole stresses.

A systematic approach was applied that used standard cementing best practices as a starting point and then identified the key factors in overcoming operation-specific challenges. In addition to the use of engineered trimodal slurry systems, NAF-compatible spacers, and loss-curing fibers, an advanced cement placement software was used to model prejob circulation rates, bottomhole circulating temperatures, centralizer placement, and mud removal. To enhance conventional chemistry-based mud cleaning and to significantly improve cleaning efficiency, an engineered fiber-based scrubbing additive was used in spacers with microemulsion based surfactant. Furthermore, a real-time monitoring software was used to compute and monitor equivalent circulating density (ECD) during the cementing operation and to evaluate cement placement in real time. Results of cement jobs were analyzed to define the minimum standards/criteria and then to verify the efficiency of the applied solutions.

The 9 5/8-in. casing / liners were successfully cemented using this methodological approach, and lessons learned were progressively used to improve on subsequent jobs. Advanced ultrasonic cement bond logging tools along with advanced processing and interpretation techniques facilitated making reliable, conclusive, and representative zonal isolation evaluation. The cement bond logs showed significant improvement and increased the confidence level towards well integrity.

After establishing field-specific guidelines over 2.5 years, continuous success was replicated in every well for all the rigs operating in this UAE field.

Depletion of conventional hydrocarbons reservoirs have led oil and gas operators to extend the boundaries and pursue production from reservoirs with high viscosity hydrocarbons that in the past were impossible to be produced and allow the hydrocarbons in place to flow to the surface with conventional production methods. With the introduction of enhance oil recovery techniques (EOR) operators has been able to economically produce from these reservoirs. The steam flood is an EOR technique that allows heavy oil hydrocarbons to be produced and increase the recovery of original oil in place (OOIP). This technique requires high temperature steam to be injected into the reservoir in order to allow hydrocarbons production, introducing challenges in order to maintain well integrity and long term life of the well. Suitable surface facilities, equipment and materials that withstand these challenging conditions are required in order to guarantee the success of the project. In a heavy oil shallow reservoir in Bahrain, a steam flood pilot project has been executed, injecting steam up to 650ºF into the injectors wells in order to enhance the hydrocarbons production in the adjacent production wells. Conventional cement systems will fail when exposed to the given conditions as the mechanical properties of such cements are not sufficient to withstand the stresses created in this extreme temperature environment. This will consequently threaten the well integrity and success of the project. In order to provide a reliable and durable zonal isolation, an engineered cement system has been introduced. This cement system possesses sufficient flexibility (low Young's modulus), and a high coefficient of thermal expansion to withstand the metal casing expansion during the heating step of the process, without failure. This cement system exhibits stable mechanical properties for a long duration during the whole process of the heavy oil production and can be mixed and pumped with conventional cementing equipment. It is placed at low (110-140°F) temperature, acquires sufficient compressive and tensile strength to withstand the heating cycles. Over 50 wells have been cemented using this technology in Bahrain. Cement bond longs and temperature logs demonstrate well integrity has been achieved, allowing the steam to be injected into the target reservoir. Furthermore, no issues have been seen related to steam break through to surface. The project has been implemented for over 4 years with no sign of wellbore integrity failure. This study covers several aspects of the design, execution and evaluation of the cement system.

In 2012 ZADCO commenced drilling operations from artificial islands in the Upper Zakum field. The field development is based on drilling extended reach wells up to 35,000 ft measured depth in three different reservoirs. More than twenty wells have been drilled from these islands so far, with the longest well reaching ~31,000 ft MD. Longer than 35,000 ft MD wells are planned to be drilled in the near future. The 9-5/8″ casing in 12-¼″ open hole is set at a measured depth of ~9,000-17,000 ft with cement designed to reach surface. There are several challenges experienced while cementing these wells, due to the narrow pore and fracture pressure gradients. Key challenges include: ECD management, maintaining fluids density and rheology hierarchy, proper centralization, lost circulation, use of NAF drilling fluids and limitations to pipe movement opportunities. Based on ultrasonic imaging of initial wells, the overall desired cement bond was not as good as desired on initial wells. Several improved practices were applied to enhance the cement bond across reservoir sections. However, the log quality was still below expectations. Hence, a more robust solution was required to successfully cement the long maximum reservoir contact (MRC) wells.

These challenges were successfully addressed and mitigated through a step-wise approach. The cement slurry designs were optimized by adjusting rheologies and static gel strength, lowering fluid loss values, adding lost circulation material and using trimodal cement designs. Mud removal was further enhanced by using better cleaners in the spacer system to provide efficient cleaning and de-emulsification. Updated mud conditioning procedures and better centralizers was also implemented.

Cement bond log and interpretation techniques were improved by using ultrasonic measurements and flexural attenuation measurements and imaging the annulus through these tools to determine actual casing centralization. The log showed a significant improvement especially across the horizontal reservoir sections.

The use of these techniques has improved cement quality and enhanced zonal isolation of the producing zones in these horizontal MRC wells and will assist in maintaining the quality for future development of the Upper Zakum field.

Managed pressure operations enable keeping the equivalent circulation density (ECD) within a narrow pore-frac pressure window during drilling and cementing while maintaining the wellbore stability and controlling formation pressures. The operation becomes more complex during a cementing job, where fluids with different density and rheology parameters are pumped downhole at varying rates, resulting in different friction pressure profiles. Proper numerical simulators must be used to model such variations and keep the downhole pressure between the pore and fracture pressures during the operation.

Managed pressure techniques and technology were critical to the successful cementation of the 7-in. liner at 12,000 ft. in a gas field in Saudi Arabia, across formations ranging from a high-pressure zone with 2.36 SG (19.65 ppg) formation pore pressure to a depleted low-pressure formation with 2.44 SG (20.32 ppg) fracture pressure. The challenge in this job was to maintain the ECD at 2.40 SG (20 ppg) throughout the cement job to avoid any losses or flow from the formations.

An automatic choke setup on the return flow line with a dynamic control system was used to drill the 8.375-in. open hole with KCl polymer mud. Precise cementing simulation was used to determine the ECD during cement placement. Numerous pre-calculations and simulations were run to evaluate various scenarios prior to the cement job to ensure effective manipulation of back pressure through managed pressure drilling (MPD) equipment to maintain ECD at the desired value throughout the cementation process.

The detailed simulations run by cementing and MPD engineers prior to the job and a collaborative approach were instrumental in defining a final cementing plan, completing the layout of equipment used for the cementing job, and executing the job with real-time monitoring of all critical parameters affecting ECD and evaluation of the cement job.

Over the last 60 years in the oil and gas industry, lost circulation has been the major nonproductive time (NPT) issue worldwide during well construction (12% of total NPT). According to industry figures, more than USD 2 billion are spent combating circulation loss each year. In the Rumaila field of Iraq, the NPT due to lost circulation is significant, estimated to be 46% of the total NPT recorded.

The Rumaila oil field is a super-giant oil field in southern Iraq; the field is estimated to contain 17 billion barrels, which accounts for 12% of Iraq's oil reserves. In the Rumaila field, at least 45% of the wells experience severe to total circulation loss at depths of 450 to 650 m true vertical depth (TVD) while drilling in the karst facies of the Dammam formation. Numerous strategies, requiring up to 24 days of rig time or 15 cement plugs in some extreme cases, have been applied by different service companies without consistent results. This has resulted in higher operating costs and delayed production. Some of the identified reasons for the low success rate are poor wellbore characterization, weak assessment of the problem, and improper execution.

The foundation of the proposed engineering and operational approach is the characterization of the wellbore with the caliper and formation image logs for better understanding of fractures and estimation of fracture volume. The approach also includes two cement slurry-type options—an increased slurry rheology with reduced density and a slurry with rapid gel strength development. The proposed approach is made complete with the engineered estimation of cement slurry volume, based on loss rate, and proper field deployment.

Developed on the basis of previous experiences and optimization of hydrostatic pressure, cement slurry rheology, and gel strength development, the engineered lost circulation solution significantly improves the lost circulation control results. Extended evaluation of cement plug jobs with the engineered design and proper execution has proven the effective impact of the solution, curing losses during the drilling phase (<3 days). This solution has proven to be an effective and key element, contributing to the increased success rate of the subsequent primary cementing operation and overcoming the challenges of zonal isolation.

Achieving zonal isolation has always been a challenge when drilling and cementing gas-producing wells in a high-pressure/high-temperature (HP/HT) environment. A generally accepted definition of a HP/HT well is one in which the undisturbed bottomhole temperature at prospective reservoir depth or total depth is greater than 149°C [300°F] and either the maximum anticipated pore pressure of any porous formation to be drilled exceeds a hydrostatic pressure gradient of 97 Pa/m [0.8 psi/ft] or pressure control equipment with a rated working pressure in excess of 68.94 Mpa [10,000 psi] is required.

In the past, HP/HT wells were drilled and cemented in the UAE using conventional cementing design and techniques. Those wells had zonal isolation concerns for cemented production strings, proving that cementing was a critical factor in the HP/HT field. In addition, the wells must bear the stresses generated from injection pressure and temperature changes and frequent cycling of injection during well testing and production. Trapped gas and oil between production and intermediate casing (abnormal annular wellhead pressure) has been globally recognized as one of the serious challenges faced by the Industry from well security and isolation perspective. To tackle the potential safety and environmental hazards of abnormal annulus pressure, better cementing practices and solutions are introduced to improve well life cycle and minimize the frequency of workover operations.

This case describes the use of self-healing cement and flexible and expandable cement to prevent cement failure due to induced stresses and optimize the isolation and ultimately deliver on the objective set for critical exploration well by the Operator.

PDO is the biggest Oil and Gas Producer in Oman drilling in several fields with a number of drilling and cementing challenges. One of the key challenges that the operator has started to encounter is sustained casing pressure (SCP) because of poor zonal isolation. Hydrocarbons are observed in B or C annuli and lab analysis confirms it is coming from one of the Limestone reservoirs. More than 4 wells that were drilled in 2012 and 2013 have been identified with SCP and others are being monitored. The drilling campaign in this particular field was halted because of SCP problems and failure to comply with government regulations. Expensive work-over operation had to be done to abandon the wells.

Owing to the fact that conventional cement systems and practices have proven ineffective, an innovative self-healing cement system was introduced. This system has the property of self-repair when in contact with hydrocarbons, seals any pathways and restores well integrity without any intervention thus providing long term zonal isolation. The system is placed conventionally in the annulus as part of the cement slurry and the healing material stays dormant till the time it sees the hydrocarbons that may flow through the cracks. Subsequently it expands and heals the cracks.

The self-healing cement system has been tried in four wells in the same field with excellent results. After more than one year of completion, no gas pressure has been observed in the annulus. The operator has standardized this system for this field for all future wells and plans to extend the use to other fields with similar issues.

This paper will cover details on the system, mechanism of work, validation process of the system, operational aspects and field implementation to elaborate how SCP problems can be overcome.

PDO is the biggest Oil and Gas Producer in Oman drilling in several fields with a number of drilling and cementing challenges. One of the key challenges that the operator has started to encounter is sustained casing pressure (SCP) because of poor zonal isolation. Hydrocarbons are observed in B or C annuli and lab analysis confirms it is coming from one of the Limestone reservoirs. More than 4 wells that were drilled in 2012 and 2013 have been identified with SCP and others are being monitored. The drilling campaign in this particular field was halted because of SCP problems and failure to comply with government regulations. Expensive work-over operation had to be done to abandon the wells.

Owing to the fact that conventional cement systems and practices have proven ineffective, an innovative self-healing cement system was introduced. This system has the property of self-repair when in contact with hydrocarbons, seals any pathways and restores well integrity without any intervention thus providing long term zonal isolation. The system is placed conventionally in the annulus as part of the cement slurry and the healing material stays dormant till the time it sees the hydrocarbons that may flow through the cracks. Subsequently it expands and heals the cracks.

The self-healing cement system has been tried in four wells in the same field with excellent results. After more than one year of completion, no gas pressure has been observed in the annulus. The operator has standardized this system for this field for all future wells and plans to extend the use to other fields with similar issues.

This paper will cover details on the system, mechanism of work, validation process of the system, operational aspects and field implementation to elaborate how SCP problems can be overcome.