Deepwater cementing poses many challenges across the world as drilling operations move towards greater water depths. The Deepwater Cementing Review Team (SPE WVS 035), gathered to provide oversight to the deepwater cementing job programs within the corporation and to insure they meet the industry standards, has reviewed so far more than 1200 jobs spread over 30 countries worldwide. About 10% of the reviewed jobs are riser-less surface casing cement jobs.
When present, shallow flow is one of the biggest risks in cementing surface casings. Not achieving zonal isolation can result in the loss of the well or expensive remedial work. Early identification of potential shallow flow is crucial as it gives time to optimize the cement job following industry best practices, such as API RP 65 and API ST 65 - Part 2.
Three important factors for a successful cement job in case of shallow flow are proper centralization, good mud removal and slurry selection. If shallow flow is present, the surface casing must be properly centralized to achieve flow around the entire casing. Conventional cement systems are widely and successfully used for surface casings. However, if shallow flow is identified, more advanced cement systems, such as foam cement or optimized particle-size distribution cement, are used.
Zonal isolation of shallow flow zones can be obtained through cementation when the engineering guidelines are followed and focus is placed on proper design and execution. A statistical analysis of the surface casing designs reviewed shows the risk of shallow gas and demonstrates that shallow flow can be prevented, after the flow potential is identified. The key is early identification of shallow flow and open discussion between the operator and the service company.
Offshore cementing poses many challenges across the world as drilling operations move towards deep-water and ultra-deep-water. As a new initiative of continuous improvement, a deep-water cementing peer review process was started early 2011. To this date, this team has reviewed more than 1200 deep-water cementing jobs in more than 30 countries worldwide.
Plug cementing makes up nearly 53% of all the deep-water jobs reviewed. The majority of the cement plugs placed are for plug and abandonment purposes; however a significant part is for loss circulation, kick-off, or squeeze. Although plug cementing comprises a big portion of deep-water cementing, it often does not get the same level of attention as primary cementing.
Specialized plug cementing software is used to design all cement plugs set in deep-water operations. The software simulates fluid interfaces, contamination during placement (both when the fluid is travelling down the pipe and when it is being placed in the annulus) and while pulling out of hole. As a final result, it provides the top of uncontaminated cement. Aside from proper job placement, good slurry design is very important. Cement slurries used for plug cementing need to be designed according to the objectives of the job. Several case histories will show lessons learned from the analysis of plug cementing operations in deep-water operations.
As the industry and local regulations gets more stringent on the evaluation and acceptance of the barrier for well integrity, the success of setting a cement plug the first time is becoming ever more critical. Getting it right the first time easily saves several days of NPT resulting in savings of millions of dollars, especially in this deep-water environment. Appropriate focus on sound engineering practices and the use of the specialized software has improved reliability of setting cement plugs in deep-water and helps operators avoid costly remedial operations.
Aranha, Pedro Esteves (Petrobras) | Miranda, Cristiane Richard (Petrobras S.A.) | Cardoso, Walter Francisco (Petrobras) | Campos, Gilson (Petrobras) | Martins, Andre Leibsohn (Petrobras S.A.) | Gomes, Frederico (PUC - RIO) | de Araujo, Simone (PUC-RIO) | Carvalho, Marcio da Silveira (PUC-RIO)
Displacing fluids in downhole conditions and for long distances is a complex task, affecting several steps on well construction. Cementing gains relevance in the moment that fluid contamination compromises cement sheath integrity and consequently zonal isolation.
Density and rheology design for all the fluids involved are essential to achieve operational success. Properties hierarchy and preferred flow regimes have been empirically defined and tend to provide reasonable generic results. Challenging operations, including ultra deepwaters and their narrow operational windows scenarios, require further knowledge of the physics involved in order to prevent undesirable events
This article presents the in house development of a software for annular two-phase flow, which analyzes fluid displacement in typical vertical and directional offshore wells, for Newtonian and non Newtonian liquids, laminar and turbulent flow regimes. The formulation proposed provides accurate results for a wide range of input parameters, including the cases in which the ratio between the inner and outer radii of the annulus is small. Operational guidelines for fluid and placement schedules are provided.
The computational work is validated by unique results obtained from an experimental test rig where detailed displacement tests were conducted. Contamination degrees were measured after the displacement of a sequence of fluids through 1192 m of vertical well. Effect of fluid density and rheology hierarchy, flow regimes and displacement concepts were investigated. The results provide relevant information for the industry and fundamental understanding on displacement of Newtonian and non Newtonian liquids through annular sections.
Most offshore wells that require artificial lift are gas lifted, as gas typically is readily available and compared to other lift systems, gas lifting is relatively inexpensive and low maintenance. However, electric submersible pumps (ESPs) can
efficiently and economically increase oil production and reserves recovery under the appropriate operating conditions. This may translate to a lower abandonment pressure in the long term—possibly reducing the total number of wells required to deplete an asset.
Since few ESPs currently are installed in offshore wells, an ESP screening "Rules of Thumb" was created as a simple guide for prioritizing offshore ESP candidates. The selection criteria focus on feasibility of installation, operability conditions
and operating practices to maximize run life, and economic considerations. ExxonMobil† and industry experience from North America, South America, West Africa, Asia, Australia, the Middle East, and the North Sea provided the basis for the study.
Welch, John Charles (Baker Hughes Inc.) | Newman, Caleb Ray (U. of Houston) | Gerrard, David Peter (Baker Hughes Inc.) | Mazyar, Oleg A. (Baker Hughes Inc.) | Mathur, Vipul (Baker Hughes Inc.) | Thieu, Vu (Baker Hughes Inc.)
The oil and gas industry is continuously looking for material and tool designs with more robustness that provides greater operational flexibility in aggressive environments. New elastomeric systems that have been enhanced at the nanometer scale have been engineered to address these needs.
Nano-enhanced EPDM showed 95-percent lower swelling rate in oil at ambient temperature. Nano-enhanced HNBR compound exhibited 15 times lower absorption in 300°F hydrocarbon fluid. Nano-enhanced FEPM compound showed 20 times lower absorption. Nano-enhanced FEPM bladder material submersed in oil at 300°F yielded a three-fold reduction in the gas transmission rate of a hydrocarbon blend containing both CO2 and of H2S. The same nano-enhanced material showed a 50-percent reduction in the degradation effects of H2S on the NBR physical properties. All of the above are lab results, and the comparisons were made to baseline commercially available rubber compounds without nano-enhancement.
Our results demonstrated that nanotechnology can be very effectively used to significantly modify properties of commonly used rubber compounds in the oil and gas industry. The oil swelling rate can be drastically reduced to give operators a greater flexibility in setting the packers and reducing intervention. Sour gas-based slowdown of material retardation translates to higher tool life. These findings can be used to design new packers, sealing elements and other elastomeric components used in downhole environment. This paper will present our recent lab results along with postulated mechanism on how nanotechnologies can impact material performance in downhole applications.
Thin films, typically < 1µm thick, are created by alternately exposing a substrate to positively-charged and negatively-charged molecules or particles, as shown in Figure 1. In this case, steps 1-4 are continuously repeated until the desired number of "bilayers?? (or cationic-anionic pairs) is achieved. Each individual layer may be 1-100+ nm thick depending on chemical properties, molecular weight, charge density, temperature, deposition time, counterion, and pH of species being deposited. The ability to control coating thickness down to the nanometer level, to easily insert variable thin layers without altering the process, economically use raw materials (due to thin nature), self-heal and process under ambient conditions are some of the key advantages of this deposition technique. These films often have properties that are better than comparable thick films (>>1µm).
2.1 Polymer Coating System
The main coating of interest is the all-polymer system containing branched polyethyleneimine (BPEI) and poly(acrylic acid) (PAA), with the final crosslinking by glutaraldehyde (GA). Details of each solution are shown below:
Pragt, Jos (Baker Hughes) | Herberg, Wolfgang (Baker Hughes) | Meister, Matthias (BAKER HUGHES Inteq GmbH) | Clemmensen, Carl Christian (Statoil ASA) | Grindhaug, Gaute (Statoil ASA) | Hanken, Knut Johan
The Integrated Under-Reamer (IUR) was developed in 2007 in a joint project between an Operator and Service company. The tool was designed to allow for unlimited opening and closing of the tool to provide selective hole opening in unstable formations e.g. unstable shale or swelling salt. Furthermore the tool should be able to close for pull out of hole (POOH) while keeping the circulation continuously on.
To accommodate for this the tool was designed to be fully integrated into the modular bus structure of the downhole BHA. Electronics were developed to activate and deactivate the tool from downlink commands sent downhole and distributed via the communication bus to the IUR. Sensors in the IUR detect the status of the tool: such as position of the cutter blades and the health of the tool. This data is transmitted to surface using the MWD pulser. The data is displayed in real-time for immediate review by the drilling team. Additional diagnostic data are stored in memory for post run analysis.
Advanced autonomous fail safe control was designed to make sure the tool can always be closed either by downlink or other procedures to allow unrestricted pulling out into smaller hole or the casing shoe. In the case of communication problems a procedure is available for back-reaming with automatically closing the blades.
A case history is presented where a water injection well needed increased clearance to run 6 5/8?? completion screens. Using the IUR, the well was opened up while drilling from a 8 ½?? pilot hole to 9.05??. The IUR was de-activated and re-activated successfully several times during drilling the section. The operational procedure is described, and caliper data are presented. The well was completed on plan. At the end an outlook will be given on future reaming on demand applications.
Drilling operations are conducted within a pressure window bounded on the lower side by the pressure of the formation fluids exposed in the open hole and on the upper side by the fracture resistance of the formation matrix. The narrowing
of this operating margin, as experienced in deepwater environments, increases the technical challenges associated with drilling operations. Typical challenges include a sharp reduction in the maximum allowable open hole drilled depth,
well control and exposure to difficult kicks, well breathing or ballooning, the risk of wellbore losses and a requirement to install multiple casing strings to get to TD.
This paper examines the phenomenon of narrow margins in deepwater, the conditions that drive it, and presents a holistic assessment of the available geological, geophysical, engineering and technology solutions for mitigating narrow margin
drilling (NMD) conditions. The solution concepts are indexed into a newly developed model called the NMD Solutions Matrix which introduces an NMD intensity scale that provides a measure of the degree of difficulty that can be expected in a well as a result of narrow margin conditions.
The applicability of the model is demonstrated in a history match of three industry case examples in two deepwater regions in the world where NMD conditions were encountered and mitigated. The NMD solutions matrix was also applied to a DW project in the planning phase which yielded insights that more clearly articulated the exposure in the project. The analyses indicate that the model, as a planning tool, has the potential to sharpen the awareness of possible challenges and enable upfront mitigation measures to reduce their impact during execution. Its application thus offers strong potential to positively impact drilling effectiveness in deepwater and yield or save considerable value in these high cost operations.
Emerging ultra high-pressure/high-temperature applications in downhole service have created the need for the development of new sealing materials. To address this emerging need, a series of modified polymeric materials were developed. The new material displayed strong mechanical properties below glass transition temperature (Tg). Above Tg, the material displayed stable elastomeric properties up to 400° C. The thermal rating of the material is beyond the available commercial thermoplastics and elastomeric materials. Furthermore, the Tg of the material can be adjusted from 97° C to 215° C. The material was aged in a crude oil at high temperature. Dynamic Mechanical Analysis (DMA) measurements were performed on the material before and after aging. The material displayed excellent resistance to the crude oil. In addition, API extrusion-resistance measurements were performed on the new material at various temperatures and various pressures. The extrusion resistance of the new material was superior to the available commercial elastomeric materials, including perfluoroelastomers. Thus, the material has great potential for use in emerging high-temperature sealing applications and other oil and gas applications. This paper describes the work involved in conducting this development work and test results.
The Hadrian-5 prospect in the United States (US) Gulf of Mexico's Keathley Canyon 919 block was drilled by the operator in ~7000-ft water depth as one of the first Gulf of Mexico wells drilled after the deepwater moratorium. This exploration well was permitted under the new regulatory requirements of the US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). These new requirements included additional blowout preventer (BOP) certification and testing, incorporation of selected API recommended practices, and certification of the well design by a registered professional engineer.
In addition to the well design regulations, BOEMRE required operators to calculate a worst-case discharge scenario and develop plans to contain that scenario. Well containment plans were developed that included the newly-formed Marine Well Containment Company's (MWCC) response capabilities.
The well was drilled between March and August of 2011 to a total depth (TD) of 19,631 ft and encountered several hydrocarbon intervals that were safely managed. The rig selected for this well was the dynamically-positioned (DP), Maersk Developer semisubmersible.
This paper describes the planning, permitting, and execution of this challenging well. Topics covered include:
• New permitting requirements for federal waters in the US
• Worst-case discharge scenario and impact on casing design
• Elimination of trapped annular pressure via well design
• Minimizing vibrations in the tuff formation of the Hadrian mini-basin
• Managing the uncertainties associated with sub-salt formation pore pressures
• Drilling and casing mobile tar zones
The well was drilled and evaluated in a safe manner with no significant incidents even though the geologic formations encountered were different than predicted.
Annular flow of non-Newtonian fluids remains a ubiquitous phenomenon in drilling operations but accurately estimating the frictional pressure loss with drill pipe rotation still poses a great challenge. Since annular frictional pressure losses increases the equivalent circulating density (ECD), it becomes imperative to accurately estimate the annular pressure loss in order to keep the ECD above the pore pressure and below the fracture gradient especially in deep offshore drilling where the pore pressure and fracture pressure are so close together.
When annular flows are encountered, a common practice is to calculate an effective diameter such that the flow behavior in a circular pipe would be roughly equivalent to the flow behavior in the annulus. This equivalent diameter definition replaces the diameter term in the friction factor, effective Reynolds number and Taylors number equations used for pipe flow thus resulting in different frictional pressure loss estimation. As a result, the selection of appropriate correlation for the respective fluids, flow regimes and putting into consideration pipe rotation has become important but has received very little attention.
In this study, the seven different equivalent diameter definitions used for estimating frictional pressure losses in an annulus were reviewed and theoretical analysis were performed on experimental data obtained from literatures to determine the effect of these definitions on wellbore hydraulics. Pressure loss ratios (PLR) which relates pressure loss with pipe rotation to pressure loss without pipe rotation weredevelopedfor each equivalent diameter definitionusing dimensional analysis techniques. These hydraulic models combined with conventional frictional pressure loss estimation were tested with experimental measurements to determine the model with an equivalent diameter definition that best predicts frictional pressure losses for power law fluids.