The Angolan government began transitioning to a zero-discharge policy for oilfield operations in 2014. To reduce the economic impact of this ruling, operators searched for ways to minimize waste volume and costs associated with treatment and handling. Total E&P Angola (TEPA) set out to equip three drillships in offshore Angola, two in Block 32 and one in Block 17, with advanced technologies to streamline the waste handling process, minimize waste volume, and recover valuable fluids. The deepwater wells were expected to produce 230,000 BOPD in 2018 in Block 32 alone. The selected waste management systems would need to be reliable, efficient, and capable of being retrofitted onto each drillship. Thermomechanical cuttings cleaner (TCC) were installed as the primary solution for the drilled solids processing. Slops treatment unit were also installed on each drillship. The TCC required ancillary equipment to comply with zero discharge constraints, including vacuum transfer systems and specialized cylindrical storage tanks for drilled cuttings. The system was sourced from various global locations and mobilized to Angola. To conform to the zero-discharge regulation ED 97/14, the typical TCC equipment layout and operations were modified. Instead of rehydrating cuttings and flushing them overboard, dried cuttings were stored and transferred for final disposal to a landfill. The entire installation was an extensive and complex project, from rig surveys and design concepts to the remote location logistics, equipment installation, and coordination across multiple groups across the operator, rig contractor and service provider. All components had to be installed on fully operational drilling rigs with challenging space constraints. Each technology package was successfully installed and commissioned, and treated thousands of tons of drilled cuttings and processed thousands of cubic meters of slops with zero accidents, incidents, or nonproductive time, despite reduced processing rates that did not affect drilling operations. Savings included recovery of base oil, decreased skip-and-ship and lifting operations, and reduced onshore slops treatments. As of Dec 2018, >25,000 metric tons of drill cuttings have been processed. Because of the zero discharge of drilling wastes, the separated solids from the TCC were rapidly cooled and stored on the drillship before bulk transfer and transport to shore. A dried solids cooler was designed and installed to reduce the 260°C (500°F) TCC output to 50°C (122°F). The dried solids coolers were the first ever implemented offshore. A new dust management system was also deployed to help control dust created by moving the ultrafine dried solids generated by the TCC's hammermill. Further, the use of efficient vacuum transport system and large-capacity cuttings storage tanks significantly reduced crane lifts that are required for standard skip-and-ship operations, thus reducing HSE risks. Once completed, the integrated technology package was the largest of their kind globally. The success of this operation was largely attributed to the careful collaboration between the operator and service provider.

Invert emulsion drilling fluids designed with an optimised range of pre-determined sized particulates have been used successfully to eliminate or minimise losses to the formation while drilling depleted reservoirs. Sands can be penetrated with up to 600 bar overbalance without encountering losses or differential sticking. Further, the wells have been drilled at pressures above their natural gradient. Selectively designing these fluids has also made it possible to successfully drill high-angle step-out sections through mature, depleted reservoirs. This paper describes the development and implementation of this technology.Fluid Design Phase - The selection and optimization of type, size and amount of particulates required takes place during the planning stage of the well based on the rock mechanics of the formations to be drilled, drilling fluid properties and the practicalities at the rig site.Execution Phase - Once the fluid design has been finalized, processes and procedures are developed to help ensure that during the project the fluid functions are designed taking account of the practicalities of the actual drilling phase. Recent case histories of the application of this technology are discussed in detail: the first case highlights a severely depleted reservoir in an extreme high-pressure, high-temperature (HPHT) field and the second case relates to extended reach wells drilled through mature reservoirs which can be segmentally depleted. Introduction Drilling severely depleted, mature reservoirs without encountering excessive mud losses, differential sticking or wellbore collapse is a considerable challenge. It can often be the case that reservoir depletion has lowered the fracture initiation gradient (FIG) to less than the mud weight required to prevent wellbore breakout in the cap rock or interbedded reservoir shales where formation pressures are at or near virgin pressure. This means that the operating mud weight window, between the applied drilling fluid pressures and the FIG, either no longer exists or is so vastly diminished that it is no longer possible to operate and remain within it. In order to meet this drilling challenge, wellbore strengthening (stress cage theory) was applied to re-create an operating mud weight window. Much has been written on this subject and it is not this paper's aim to go into great detail on the theory but instead to highlight how this technology was successfully used by a major operator in the UK sector of the North Sea. The two wells that are discussed demonstrate the flexibility of the technology from its utilization on an extreme HPHT well with a severely depleted reservoir to a long step-out well with a segmentally depleted reservoir. Losses on both these wells were viewed as high risk threats, possibly inevitable, yet the correct application of the wellbore strengthening technology helped to ensure that no significant downhole losses were observed. The application of wellbore strengthening technology (Fig. 1) involved the addition of sized particulates to the oil-based drilling fluid. These particulates consisted of graded ground marble (CaCO3) and sized resilient graphitic material (RGM) and were selected (designed) based on the rock mechanics and architecture of the individual well. The strategy was to pre-treat the drilling fluid with the selected particulates before entering the depleted formation and to maintain its designer properties throughout the section. The key to the success of this process depends upon it being preventative, i.e., the particulates have to be present in the correct size range and concentration before fractures are initiated by the excessive circulating pressures.

Foamed cement was successfully used in the riserless section of an ultradeepwater well located in 11,900ft water depth. Foamed cement was selected to minimize operating costs and provide flexibility to adjust slurry density on a short notice. The seawater column exerted 5,319.1-psi hydrostatic pressure on the annulus. Consequently, nitrogen (N2) density could no longer be neglected. This paper presents simulations performed in preparation for the job, operational considerations, and post-job evaluation. The lead slurry needed a density of 1.25 SG and develops a compressive strength of at least 300 psi within 48 hr. Considering the cost and challenges associated with outsourcing resources under current Covid-19 pandemic restrictions, the foamed cement system was preferred over chemical- or particle- extended cement or blend systems. The N2 ratio for the foamed cement slurry system was 700 scf/bbl. With a base slurry pumping rate of 5 bbl/min, the required N2 pumping rate was 3,500 scf/min, which was greater than the capability of a single N2 pump (3,000-scf/min rate). Because the rig deck space could not accommodate three N2 pumps, one pump would serve as backup; thus, the final plan consisted of using two N2 pumps simultaneously. Two parallel foamed slurry treating lines were rigged up to reduce the fluid velocity in a single line. All laboratory testing was conducted locally. Additives used in the foamed slurry were environmentally friendly. A proprietary process-control system was used during the cementing operation and automatically synchronized the N2 pumps and foam pump rates with the base slurry rate. The cementing crew consisted of 11 individuals, including 2 client representatives. The entire pumping operation was completed in 10 hr. A total base slurry volume of 1016.2 bbl was continuously mixed and pumped at the density of 13.35 lbm/gal (1.60 SG). The resulting foamed slurry volume was 1387.0 bbl with an average foam quality of 27.8% and foamed slurry density of 10.5 lbm/gal (1.26 SG). A total of 119 metric tonne of class G cement and 30,711 L of N2 were consumed during the pumping operation. The lead slurry was followed by 603.9 bbl of 15.86 lbm/gal (1.90 SG) class G cement tail slurry and 349.7 bbl of seawater for displacement. The final surface pressure was 594.6 psi. The lead slurry reached the seabed and the float shoe check was positive. No casing subsidence was observed. Using foamed cement slurry in such extreme conditions demonstrated its robustness and reliability. Through formalized and methodical risk assessment, the team was able to identify and implement mitigating measures that led to an outstanding result. This application also confirmed that N2 density should not be neglected when high-hydrostatic pressure is involved.

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.