Potential reservoir formation damage was avoided when curing up to 87.4 m3/hr (550 barrels per hour (bbl/hr)) losses of drilling fluid in a carbonate reservoir. In addition to traditional lost circulation assessment and treatment consideration, self-degrading fibers were used as part of the lost circulation system, and these preserved the reservoir from any consequential formation damage. The treatment procedure consisted of pumping a given volume of treatment pill through bypass ports present in the drilling string and displacing it down to the loss zone (located 56 m below the bit). Managed pressure drilling (MPD) was used to minimize hydrostatic pressure above the said loss zone during pill placement (statically under-balanced mud weight). Since drilling was meant to continue after the treatment, the pill had to be squeezed to and through the reservoir to prevent loss from re-occurring when drilling resumed. The only available solutions at the time of need were either a thixotropic acid soluble cement plug (TASCP) or, the proprietary degradable fiber. Preference was given to the degradable fiber since it involved less rig time and does not need any subsequent dissolving treatment. An appropriate spacer was pumped ahead and behind the degradable fiber to prevent intermixing of incompatible fluids. The treatment was pumped using the rig mud pumps. The loss rate registered prior to the treatment was 87.4 m3/hr (550 bbl/hr) at a pumping rate of 2650 l/min (700 gal/min). The equivalent circulating density (ECD) was 1.22 SG (10.2 ppg). Out of 19 m3 (120 bbl) of prepared degradable fiber pill, 15.6 m3 (98 bbl) were pumped and displaced into the reservoir, leaving the estimated top of the pill at 5850 m measured depth (MD). The top of the loss zone was estimated to be at 5856 m TVD/MD. The bypass port was then closed. It was then observed that the loss rate reduced to 3.65 m3/hr (23 bbl/hr) when circulating the hole clean at 5800 m TVD/MD and maintaining the same ECD of 1.22 SG (10.2 ppg) with the help of MPD equipment; pumping down string at 3028 l/min (800 gal/min) and boosting the marine riser at 757 l/min (200 gal/min). This pill was designed to self-degrade after 4 days. The pill lasted for 5 days, and the loss rate came back to its original level, providing evidence that the fiber had self-degraded as expected. MPD helped minimize further loss through the reduction of hydrostatic overbalanced pressure. Later, openhole wireline logs were run and did not reveal any change in expected porosity or permeability. This paper presents a case study in which the introduction of degradable fiber through a bypass port in the bottomhole assembly (BHA) cured severe loss of nonaqueous fluid (NAF) in a deepwater exploration well without damaging the formation. This case provides evidence that properly designed fiber-based pills can be used in the reservoir section without any major consequences on the well production potential.
Four deepwater wells in the Gulf of Mexico were identified for permanent abandonment in accordance with local regulations. The abandonment plan called for multiple cement plugs to isolate the production zones from seabed in each well. The most challenging cement plugs in each well were the ones directly above the production packer isolating the casing-tubing annulus and the production tubing. To avoid cement left in the Christmas tree at seabed and potential plugging off any valves in the manifold, cement plugs could not be placed the direct way, pumping down the production tubing. An unconventional approach was proposed to address the challenge. It involved reverse placement of cement plugs, which is not common in deepwater even in these days. Using this technique, cement was pumped down the casing-production tubing annulus and, through perforations, back up the production tubing. Risk analysis indicated very low likelihood of plugging off any valves in the tree. However, this configuration did not allow use of mechanical separators between fluids to prevent intermixing. Additional challenges in placing the plug were the high deviation of the section and the completion brine in the wellbore. Simulation of reverse placement is not possible with existing software. Therefore, the jobs were designed using experimental software, which enabled the design engineer to accurately reconstruct field conditions. Additional attention was given to the job procedure to minimize contamination with the brine and optimize cement placement. Viscous spacer was pumped ahead and behind the slurry to displace the brine. The slurry was designed with low fluid loss to be squeezed through perforations in the production tubing without plugging them off. A total of seven plugs were placed using the reverse placement technique. Specific requirements with regards to the top of cement and plug integrity had to be met before any of the cement plugs could be accepted by the operator. All plugs were tagged and pressure tested successfully in the annulus as well as inside the production tubing on the first attempt. As a result of the campaign, the four wells were abandoned as per schedule and within budget.
Deepwater is one of the most technically and logistically challenging environments for cementing operations because of the risks associated with the conductor and surface casing cementing. Understanding the technical challenges, and mitigating the geological risks such as low temperature at seabed and fracture gradient, as well as shallow flow hazards including shallow water flow and gas Hydrates are key to designing cement slurries that can meet deepwater specifications and provide required zonal isolation. This paper will discuss the real challenges faced during the cementation of critical surface casing for a major operator in India. The maximum operating water depth was 2,965 m [9037.3 ft]. Shallow gas flow, was encountered during the drilling of top hole sections. A low seabed temperature of 2 ºC [35.6 ºF] was also encountered in all the wells, and the narrow margin between the pore pressure and fracture gradient necessitated the requirement of lightweight cement slurry of 1378 kg/m3 [11.5ppg]. All of these challenges were resolved by using an innovative cement system based on Optimized Particle Size Distribution (OPSD), combined with a proprietary low temperature gas migration control additive, used for the first time in India. The zonal isolation was achieved using the OPSD system and a proper gas migration control additive system.
Summary To determine which salt-based cement system (potassium chloride or sodium chloride) was suitable for cementing across halite and anhydrite salt sections in West Africa, eight slurry recipes were tested to assess how formation salt contamination would affect slurry properties. The formation salt used for testing was sampled from a deepwater, presalt well in Angola. The recommendations developed from the laboratory study were implemented in 10 projects across West Africa over 5 years with 100% operational and well integrity success. A candidate deepwater well was selected in which the surface and intermediate strings penetrated salt formations. Four slurry designs (a lead and tail slurry used on each casing string) were programmed. Each slurry was designed and tested as two distinct systems using potassium chloride and sodium chloride salt, respectively, yielding a total of eight slurry designs. Using the methodology and data presented by Martins et al. (2002), the mass of dissolved formation salt that each slurry may receive during placement was estimated and duly incorporated into each slurry design. Subsequently, the salt-contaminated slurries were tested and compared with the properties of the initial uncontaminated slurries. On the basis of these results, conclusions were then made on which salt slurry system (potassium chloride or sodium chloride) exhibited better liquid and set properties after contamination with formation salt. Subsequently, this knowledge was applied to 10 projects across three countries in West Africa. This study showed that when the contact time of liquid cement slurry to salt formation was low—typically when the salt-formation interval across which the cement slurry flowed was less than 100 m thick—the level of formation salt dissolution entering the slurry during placement was limited. In this case, a potassium chloride salt-based slurry delivered improved liquid and set properties as compared with a sodium chloride salt-based slurry. In the field, this knowledge was applied in all oilfield projects cemented by an oilfield service company between 2015 and 2020. This included deepwater, shallow offshore, and onshore wells. All related salt-zone cement jobs, including sidetrack plugs, placed across the salt formations were successful on the first attempt. In an absence of industry consensus around salt-formation cement slurry design, this paper validates a guideline for West Africa, based on results from laboratory testing and 5 years of field application. In contrast to current literature that recommends only sodium chloride salt-based slurry designs across halite or anhydrite salt intervals, this work demonstrates that potassium chloride salt-based slurry systems can effectively be used to achieve well integrity where a halite or anhydrite salt interval is less than 100 m (328.1 ft) thick.
To determine which salt-based cement system [potassium chloride (KCl) or sodium chloride (NaCl)] was suitable for cementing across halite and anhydrite salt sections in West Africa, eight slurry recipes were tested to assess how formation salt contamination would affect slurry properties. The formation salt used for testing was sampled from a deepwater, presalt well in Angola. The recommendations developed from the laboratory study were implemented in 10 projects across West Africa over 5 years with 100% operational and well integrity success. A candidate deepwater well was selected in which the surface and intermediate strings penetrated salt formations. A total of four slurry designs (a lead and tail slurry used on each casing string) was programmed. Each slurry was designed and tested as two distinct systems using KCl and NaCl salt respectively, yielding a total of eight slurry designs. Using the methodology and data presented by Martins et al. at the 2002 IADC/SPE Drilling Conference (SPE-74500-MS), the mass of dissolved formation salt that each slurry may receive during placement was estimated and duly incorporated into each slurry design. Subsequently, the salt-contaminated slurries were tested and compared with the properties of the initial uncontaminated slurries. Based on these results, conclusions were then made on which salt slurry system (KCl or NaCl) exhibited better liquid and set properties after contamination with formation salt. Subsequently, this knowledge was applied to 10 projects across three countries in West Africa. This study showed that when the contact time of liquid cement slurry to salt formation was low—typically when the salt formation interval across which the cement slurry flowed was less than 100 m thick—the level of formation salt dissolution entering the slurry during placement was limited. In this case, a KCl salt-based slurry delivered improved liquid and set properties as compared with a NaCl salt-based slurry. In the field, this knowledge was applied in all oilfield projects cemented by an oilfield service company between 2015 and 2020. This included deepwater, shallow offshore, and onshore wells. All related salt-zone cement jobs, including sidetrack plugs, placed across the salt formations were successful on the first attempt. In an absence of industry consensus around salt-formation cement slurry design, this paper validates a guideline for West Africa, based on results from laboratory testing and 5 years of field application. In contrast to current literature that recommends only NaCl salt-based slurry designs across halite or anhydrite salt intervals, this work demonstrates that KCl salt-based slurry systems can effectively be used to achieve well integrity where a halite or anhydrite salt interval is less than 100 m [328.1 ft] thick.
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