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.

Traditionally, service companies have had to place several consecutive cement plugs to successfully kick off wells deeper than 3,500 meters. Within the scope of integrated projects in Southern Mexico where wells are usually deeper than 5,000 meters, the low success rate for traditional balanced plug cementing has jeopardized operational efficiency and financial results. Several plug failures made it clear that the volumetric calculations and other known engineering best practices that were implemented were not sufficient to bring the success rate to an acceptable level. In our field study, we implemented an innovative simulation and design method that allows for engineered optimization of the plug placement design and that shows how a 100% success rate in plug cementing can be achieved in wells as deep as 5,720 meters, with hard formations and an OBM environment. The value of this new method resides in a live analysis and display of the fluid interfaces, mixing both while traveling down the pipe and up the annulus and resulting in the output of an estimated top of uncontaminated cement after pulling the pipe out of the hole. The new workflow reveals the effect of each variable affecting the amount of contamination of the cement slurry downhole and gives the engineer the opportunity to optimize the plug placement design before job execution to reach the highest possible top of uncontaminated cement after execution. The results obtained with the new engineering tool and a precise operational field execution has moved the theory of plug placement from the best practice library to the reality of the plug placement operations.

Accretion is a common phenomenon that affects drilling operations in the Orinoco Heavy Oil Belt. The main reservoir, where most horizontal sections are drilled, is the Oficina Formation. Accretion negatively impairs operational efficiency, thus generating stuck pipe incidents, problems while tripping due to high torque and drag values related to friction factors, and the unrecommended backreaming operations. In addition, accretion causes excessive fluid surface losses linked to plugged shakers screens. This document shows the laboratory tests and successful field results obtained from the combination of specialized surfactant and lubricant agents working in synergy to reduce the accretion effect. The laboratory test demonstrated the synergy between the lubricant and surfactant in different tests, such as lubricity, accretion, and permeability damage testing. In the field, positive results were achieved in nine horizontal wells, thus increasing operative efficiency by reducing stuck pipe incidents, backreaming operations, and unplanned trips. This impact over flat times was also accompanied by a fluid waste reduction that improved the shakers’ screen usage and reduced the amount of oil coating the cuttings, which facilitated the treatment process and minimized environmental impact.

A typical well scheme for a deep well usually has five casing sections that can include a liner string. However the number of casing strings is given by the number of intermediate sections required to isolate unstable formations prior to reach the pay zone. The industry has defined the casing sizes following a standard well design of five casing string (Table 2) that can include liners depending on the well requirements. The clearance between casing string is based on a standard drift which is related to unobstructed tolerance through pipes that is associate to the casing geometry such us ovality and casing straightness, this design criteria does not take in account other phenomenons that can compromise the effectiveness of a well design such us the effect of surges forces while running casing strings. In prescence of competent formations and shallow wells, the design citeria explained above does not represent risk in term of loss circulation during running casing or cementing operations. However in the Mezosoic fields at Souht of Mexico (Figure 1), the geological structures are domain by unstables clay domes and eventually salt domes (Figure 2) that are located between 3,200 m - 3,700m. Also the drilling environment is characterized by narrow mud windown. As a consequence the wells are completed with six casing string. The wells drilled in this fields are classified as high risk wells due to the potential hole problems related that include massive lost circulation. The geometry of the wells is also an issue since the use of non conventional casing sizes to isolate unstable formations left low clearance between casing strings that induce lost circulation when running casing. This paper describes the actions taken to reduce massive loss circulation and define an “Anti surge methodology to mitigate severe loss circulation” when running non-conventional casing sizes with reduced clearance between casing strings in some fields located at South of Mexico.