The operator was drilling their first high-pressure high-temperature (HPHT) exploration well with narrow pressure window in a swamp area of East Kalimantan. The gas field was discovered in 1977 and production started in 1990. Since then, more than 1500 wells have been drilled in this area yielding a total gas production of 9.7 Tcf. Currently T field enters established mature field status which has quite marginal reserves. Therefore, further exploration is seen as one of the solutions to locate additional reserves to enhance overall gas production. The well was drilled directionally with no offset well nearby. While drilling the 6-in open hole section, an unexpected high-pressure zone was penetrated. The zone condition was made worse by lost circulation and a high gas reading. Two cement plugs were placed using a managed pressure cementing with pump and pull method. The first plug was set by applying surface back pressure (SBP) to maintain equivalent bottom hole pressure (BHP) between lowermost pore pressure (PP) and fracture gradient (FG) at the previous shoe. After pumping 1 m3 of cement into the annulus, pump and pull operations commenced. While performing post job circulation on the first plug, it was observed that the returned fluid density at surface was less than original mud weight, indicating the possibility of contaminant invasion from formation. After waiting for the cement to reach 500 psi compressive strength, pressure buildup was observed when annulus was shut-in, indicating an inadequate pressure seal across the cement plug Applying lessons learned from setting the first plug, new design considerations were implemented such as increasing cement volume in the annulus to 4 m3 prior to the pump and pull operation to minimize cement overlapping risk and applying SBP at BHP near FG. A contingency plan was in place to determine the appropriate SBP value to be applied whenever the pumping rate was changed. A second plug job was performed safely and flawlessly by achieving the top of cement as desired. A successful inflow test was performed with indication of no contaminant invasion nor pressure bypass around the cement plug. The rig was able to continue its next operation to sidetrack the well. This paper presents the design considerations, methodology applied, and lessons learned two managed pressure cement plugs using pump and pull method in a well bore with a narrow pore-frac window where the new techniques were implemented to enhance success of the plug job despite the complexity and risk inherent with an underbalanced operation.

HPHT well subjects zonal isolation and long term cement integrity into critical factor to achieve long term production life. Repeated cycles of high differential pressure and temperature tend to break bonding between cement, casing and formation. Microannulus as consequence of debonding will provide space. At gas wells, it will provide space for gas migration which may lead to sustained casing pressure. Providing zonal isolation is also important to ensure there will be no communication between two different formations or reservoirs This paper discusses the design, execution and evaluation of cement technology implemented at 9 5/8-in HPHT intermediate liner. Special softwares were used to simulate gas migration risk and stress analysis to cement sheath. High risk gas migration and microannulus were expected based on sofware results. An expandable cement system was identified as a solution and deployed successfully. In order to achieve better understanding of behaviour of cement slurry at field application, laboratory experiments were performed. To achieve long term cement integrity, it is not only about design of cement slurry, mud removal is one of the key factor need to be considered. Best practices were perfomed to achieve the highest mud removal efficiency. Expansion test was perfomed by using pressure curing chamber at 247°F. Expansion was detected for six days simulation which was considered as enough based on stress analysis simulation of compression, traction and microannulus cement sheath performed. It was indicated that expandable cement managed to eliminate microannulus which was created by pressure and temperature changes. Evaluation was performed by locating pressure sensor at the A annulus of 9 5/8-in liner and 13 3/8-in casing. The sensor indicated zero pressure at the annulus while drilling next two more section and during the production life of the well

DESCRIPTION:One of Indonesia historic oil producing field in the Sumatera Island is constantly developed in order to maintain production at a sustainable level. The number of wells drilled is between 250 and 400 per year due to the highly depleted nature of the field.One of the main issues that jeopardize the drilling efficiency in this field is the challenge of drilling and cementing under losses; this can result in a poor cement job quality and/or not being able to bring cement up to surface. A bad zonal isolation can cause loss of steam efficientcy, excessive water production and loss of well integrity requiring costly remedial jobs yielding delayed production since the heavy oil reservoir in this area is produced using the enhanced production technique of steam flooding APPLICATION: A solution implemented to cure the losses during the drilling and cementing consists of a newly developed reinforced composite mat fiber and granule based loss circulation solution coupled with a diagnostic computer aided software. The Software validates the efficiency of the pill design in curing the losses while drilling and/or cementing. A total of 50 wells were treated, this technology was used in 48 wells while cementing and 2 wells while drilling with a high success rate. RESULTS OBSERVATIONS AND CONCLUSIONS:This paper will first detail the standard techniques that were used historically in order to combat losses while drilling, then will describe the new approach using the reinforced composite mat technology, and shows quantitative results achieved mitigating lost circulation challenges and ensuring competent zonal isolation which led to eliminating remedial work in more than 60% of the wells. SIGNIFICANCE OF SUBJECT MATTER:This innovative approach has increased success rate in bringging cement back to surface during well construction on the first attempt from 2% with conventional techniques to more than 60% using Composite Mat Fiber Technology.

Harbour Energy began offshore exploration in the Andaman Sea in North Sumatra, Indonesia with the Timpan-1 well. During the planning phase, reservoir sections of the well were identified that contained circa 5-15% of CO2 levels as per the offset well data, which are corrosive environments and can cause cement sheath degradation. This paper presents the decision process used in selecting a suitable system for the CO2-rich environment and the first-time application of pumping novel self-healing and CO2-resistant cementing system with its capability to self-heal upon contact with CO2. Conventional Portland cement degrades in CO2-corrosive environments and combined with cement sheath damage by downhole stresses, long-term well integrity will be compromised. The auto repair capabilities provided by the novel cement system when in contact with CO2 leaking-fluids ensure long-term well integrity. Although self-healing-to-hydrocarbons cements have been widely used in the industry, use of this newly developed novel self-healing CO2-resistant cement was implemented for the first time in a primary casing job. To ensure blend consistency of the novel self-healing CO2-resistant cement, a number of quality control processes were developed with extensive laboratory testing and implemented for the complete blend lifecycle management. Implementation of this novel self-healing CO2-resistant cement in a deep-water primary casing job requires validation of crucial factors meet the requirements of achieving the long term well integrity. During the preparation phase, this cementing system was exposed to a high-CO2 corrosive environment over an extended period to analyze the robustness. The results showed superior properties compared with a conventional Portland system. The self-healing properties, analyzed with the use of an actual crack in the set cement and observed to the point where the crack closed, demonstrated continued cement integrity. Slurry stability tests produced excellent results. Blend flowability and robustness tests were performed at a regional laboratory using specialized equipment and determined the blend to be suitable for offshore operations. In implementation phase, by adhering to the project management process developed, the primary casing cement job was successfully performed without incident using conventional cementing equipment and practices. Good cement bond was obtained across the main zone, and the rig was able to continue its operations to perforate and well test the well. The 2001 Greenhouse Gas (GHG) Protocol's guidelines categorized business GHGs as scope 1 emissions, scope 2 emissions, and scope 3 emissions. The aim of this emission classification system was to help organizations measure and manage their carbon footprint (www.greenbusinessbureau.com 2022). Scope 1 emissions are GHGs released directly from a business. Scope 2 emissions are indirect GHGs released from the energy purchased by an organization. Scope 3 emissions are also indirect GHG emissions, accounting for upstream and downstream emissions from a product or service, and emissions across a business's supply chain. The novel self-healing CO2-resistant cement produces 63% less CO2 compared with a conventional Portland cement system. Implementing the novel slurry system will significantly reduce Scope 3 of CO2 emission that is embedded during the manufacturing of the materials used. In addition to that, due to its self-healing capability, the novel CO2-resistant cement will contribute on Scope 1 CO2 emission reduction by eliminating the need to perform remedial work in case of a well leak. The solution meets the long-term well integrity requirement and is in line with the global commitment to reduce the carbon emission footprint.

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