Zhang, Feifei (Halliburton) | Kang, Yongfeng (Halliburton) | Wang, Zhaoyang (Halliburton) | Miska, Stefan (The University of Tulsa) | Yu, Mengjiao (The University of Tulsa) | Zamanipour, Zahra (The University of Tulsa)
This paper identifies wellbore stability concerns caused by transient surge and swab pressures during deepwater drilling tripping and reaming operations. Wellbore stability analysis is presented that couples transient surge and swab wellbore pressure oscillations and in-situ stress field oscillations in the near wellbore (NWB) zone in deepwater drilling.
Deepwater drilling is usually subjected to narrow drilling windows and significant wellbore pressure oscillations during tripping/reaming because of well depth. However, integration of transient surge and swab pressure analysis, and its effects on in-situ stress analysis around the wellbore, is rarely industry studied.
A transient surge and swab model is developed by considering drillstring components, wellbore structure, formation elasticity, pipe elasticity, fluid compressibility, fluid rheology, etc. Real-time pressure oscillations during tripping/reaming are obtained. Based on geomechanical principles, in-situ stress around the wellbore is calculated by coupling transient wellbore pressure with surge and swab pressure, pore pressure, and original formation stress status to perform wellbore stability analysis.
By applying the breakout failure and wellbore fracture failure in the analysis, a workflow is proposed to obtain the safe operating window for tripping and reaming processes. Based on this study, it is determined that the safe drilling operation window for wellbore stability consists of more than just fluid density. The oscillation magnitude of transient wellbore pressure can be larger than the friction pressure loss during normal circulation process. With the effect of surge and swab pressure, the safe operating window can become narrower than expected. Although it is stable and not a concern during a normal penetration process, the wellbore stability can become problematic. By using the methodology described, unnecessary breakouts and borehole failures during tripping and reaming can be avoided. This work can also be used in the next generation of drilling automation.
This study provides insight into the integration of wellbore stability analysis and transient surge and swab pressure analysis, which is rarely discussed in the literature. It indicates that, when surge and swab pressure analysis is not carefully performed, the actual safe operating window can become narrower than originally predicted.
Panamarathupalayam, Balakrishnan (Schlumberger) | Khvostichenko, Daria (Schlumberger) | Phatak, Alhad (Schlumberger) | Zhang, Joyce (Schlumberger) | Green, Sarah (Schlumberger) | Gadiyar, Balkrishna (Schlumberger) | Lecerf, Bruno (Schlumberger) | Allogo, Clotaire-Marie Eyaa (Schlumberger)
This paper describes the development and qualification of an oil-based gravel pack carrier fluid. The fluid is a water-in-oil emulsion prepared with base oil, brine, and emulsifier. Densities up to 13.6 lbm/galUS can be achieved using oil-to-brine ratios between 45:55 and 60:40. This oil-to-brine ratio range is such that the fluid exhibits low viscosity and Newtonian rheology, making it suitable for alpha/beta gravel pack placement. Extensive laboratory testing was performed to characterize fluid properties at various temperatures and oil-to-brine ratios. Performed in 4-in pipe, tests evaluated pressure drops at rates of up to 15 bbl/min, which revealed that the friction pressure generated by this fluid matches established empirical correlations for Newtonian fluids in turbulent flow. Finally, a full-scale yard test was performed to demonstrate that the fluid can be mixed using standard mixing equipment and used to successfully place alpha/beta gravel packs.
Reddy, B. R. (Aramco Services Company: Aramco Research Center-Houston) | Contreras, Elizabeth Q. (Aramco Services Company: Aramco Research Center-Houston) | Boul, Peter J. (Aramco Services Company: Aramco Research Center-Houston)
Achieving quality cement performance in deep water wells with large amounts of salt present requires fundamental understanding of the salt effects on the interactions of cement additives with cement on the slurry performance. Many problems encountered later in the life of the well can be traced to slurry performance issues during placement and the initial setting process. Cement slurry designs for an oilwell can range from simple to highly complex depending on the geology, lithology, placement logistics, wellbore conditions and long-term performance. Logically designed cement slurry formulations and dependable additive behavior are critical to meeting cement performance requirements. Formulations can include mineral admixtures added in substantial quantities and additives in smaller (<2% by weight of cement) quantities. The performance of the additives in cement slurries depends strongly on competitive adsorption on cement and mineral surfaces. Adsorption interactions are directly influenced by downhole temperature, the nature of the formation, and the mix water composition. These aspects underline the need for understanding additive interactions with cement under wellbore conditions.
Of particular relevance to deep water cementing is the performance of additives in sea water containing monovalent and divalent salts with chloride and various other anions present in amounts close to 4% by weight. The problem of additive performance becomes even more of a concern when cement is placed against salt formations. High ionic strength of sea water or of a sea/fresh water slurry placed against a salt formation, can compress the electrical double layer of cement clinker particles, alter chain conformations of ionically charged or hydrophobically modified polymeric additives, or change the solubility of additives. Additives may perform extremely well in fresh water slurries, but may perform poorly in slurries with high salt content. Additionally, the salt itself can affect cement performance. For example, sodium chloride is a set accelerator in small quantities (=13% by weight of cement) while it functions as a retarder in large quantities.
The objective of this presentation is to gain molecular level understanding of relationships among additives based on chemical structures, adsorption onto cement surfaces, and the mix water ionic strength.
In this study, typical additives for dispersion and retardation are contacted with Portland cement in deionized water, synthetic sea water, water containing 2% to saturation level of NaCl or divalent salts in a formation brine. The reactions were analyzed by isothermal calorimetry, UV/Visible spectroscopy and rheology. The interpretation and implications of laboratory results are presented.
The offshore industry's current trend is driving towards ultra deepwater wells, combined with deeper total depths. In order to be able to set and run larger and heavier casing strings with hook loads approaching or exceeding 2.5 million lbs, an innovative heavy duty landing system has been developed and put on the market.
Such systems must be capable of landing heavy loads while ensuring slip crush resistance. It includes an extended slip with enhanced design (coupled with a new greasing system), a 2.5 million lbs landing carrier and a pipe with a thick walled high strength material section, a light weight tube, and a rotary shouldered connection.
One of the current operational challenges with existing heavy duty landing strings is linked to the positioning of the slips, in particular when using extended slip designs. The limited length of the slips area requires additional time for proper positioning and set up. To address these issues, a new slip proof section design has been developed: the combination of an extended crush proof section and the absence of a heat affected zone in that particular area decreases running time while completely eliminating the risk of setting the slips on a weak point.
The "Spiri-Reinhold pipe crushing" formula has been used to design this system. However, considering the approximation of this model's results, crushing performance has been assessed using the Finite Element Analysis, as well as physical tests performed with a specifically designed pulling unit. These full scale test results have been compared to the ones obtained with both the Finite Element Analysis and the standard "Spiri-Reinhold pipe crushing" formula.
Ferreira, Marcus V. D. (Federal Univ. of Santa Catarina) | Hafemann, Thomas E. (Federal Univ. of Santa Catarina) | Barbosa, Jader R. (Federal Univ. of Santa Catarina) | da Silva, Alexandre K. (Federal Univ. of Santa Catarina) | Hasan, Rashid (Texas A&M University)
The thermal behavior of a deepwater well was simulated using an existing mathematical model in which a rigorous flow-pattern based multiphase flow model was employed to predict the pressure drop of the hydrocarbon stream. The heat transfer model relied on the energy equation for the hydrocarbon mixture and on a radial thermal resistance network between the wellbore and the formation. Different annulus convection and thermal formation models were evaluated.
Production pressure and temperature results were compared with field data and with a commercial software package, showing good agreement with both. The model was able to capture important quantitative phenomena associated with the wellbore heat transmission (e.g., lithologic column and annulus fluid type). The simulations showed that for short production times the heat transfer to the formation was significantly influenced by the wellbore thermal resistances, namely the cement sheaths and the nitrogen present in the production annulus. As the production time increased, the formation became the dominant thermal resistance. The mathematical model was capable of handling real production scenarios, such as the impact of a watercut time-dependent behavior on the temperature distribution in the wellbore.
Lost circulation is a major challenge in well construction operations, especially where drilling margins are narrow or in pressure-depleted reservoirs. Wellbore strengthening techniques (e.g., StressCage) have successfully been used to increase formation fracture resistance and reduce mud losses during drilling operations. The increase of fracture resistance in sands has been used to improve wellbore stability (through the use of higher mud weights), reduce casing requirements, and access resources that may have been undrillable using conventional drilling methods.
The StressCage technique requires the estimation of the width of an induced fracture at a target fracture length for a given wellbore pressure. This estimation involves either a finite element calculation or a closed form line crack analytical solution. Populating and running the finite element solution requires specialized software and expertise, which has limited its use to larger operators and service companies that are staffed with geomechanics experts. The closed form line crack analytical solution is both simple to implement and easy to use, but it assumes transverse isotropic in-situ stress conditions relative to the borehole axis, which is almost never the case in the presence of a deviated well. This assumption results in either the underestimation of the calculation of the fracture width in the presence of deviation or abnormal in-situ stresses, which can result in a failed implementation of a StressCage formulation.
We have developed a new semi-analytical line crack solution that accounts for stress anisotropy from either borehole inclination or abnormal in-situ stresses. This new solution is simple to implement. The calculation of the fracture width has been verified against finite element calculations through a range of stress anisotropies, borehole sizes, Young’s moduli, Poisson’s ratios, and target increases in wellbore strength.
Wight, Jim (Halliburton) | Craddock, G. G. (Halliburton) | Haggerty, Dennis (Halliburton) | Rojas, Fabian (Halliburton) | Montiverdi, Jonathan (Halliburton) | Yadav, Arvind (Halliburton) | Magdaniel, Manuel (Halliburton) | Rios, Federico (Halliburton) | Harive, Kevin (Halliburton)
This paper discusses using a perforating toolkit as a computational paradigm to provide perforating solutions to field personnel. This toolkit provides an extensive list of charges and gun systems and generates the effects on the target rock and overburden pressure. Outputs include depth of penetration and casing hole sizes. It has an improved graphical user interface (GUI) and updated algorithms based on data from the flow laboratory.
The perforating toolkit uses up-to-date API data as the basis for the calculations; simulations are based on parameters set by the user and outputs are in a graphical format, showing the perforating performance within the reservoir. The perforating toolkit software is designed to use improved data obtained from recent laboratory testing. The most up-to-date flow laboratory testing was used to generate the algorithms for the perforating toolkit, generating more precise algorithms and producing improved perforation predictions. Testing involved a broader range of data than was previously used, allowing the software to make more accurate predictions. This new tool was benchmarked using laboratory testing, which demonstrated the quality of the paradigm and its functional use for improved downhole perforating. The software provides the field user with a tool to predict downhole shaped-charge performance quickly and in a cost-effective manner. The models also allow a number of parameters to be varied for a better comparison of different scenarios.
This paper discusses how new data across a broader range from the flow laboratory was used to improve the basic software algorithms and help provide the most accurate prediction of downhole charge performance.
Reliably deploying liner hangers in offshore applications is critical to successful wellbore construction. This case study reviews the pre-job planning, collaboration, and deployment of the first metal-to-metal sealing and anchoring expandable liner hanger (ELH) in the Gulf of Mexico. A set of particularly problematic deepwater wells will be discussed. The intensive collaboration between the service company and operator, as well as the job-specific design considerations of the metal-to-metal hanger and service tool, will be included.
The operator and service company collaborated to quantify and implement agreed-upon design concepts. Additional collaboration was required during the job preparation for a challenging well with multiple sidetracks from previous unsuccessful alternate-technology liner-hanger deployments. Collaborative design considerations for the hanger include features to handle extreme tensile loads through the service tool prior to hanger installation and through the liner hanger post installation. Job-preparation collaboration included planning a fit-for-purpose job, with an in-depth look at the parent casing, hanger, wellbore geometry, and other critical aspects of the job. Additional discussion will center on the benefits of metal-to-metal sealing technology at the liner top in conjunction with elastomeric-contingency sealing technology.
This paper disseminates technical information to increase operator awareness of a new technology and its application. The collaboration between the service company and operator describes a needed trend in the industry to successfully construct wells in a challenging environment. Developing well-specific, fit-for-purpose equipment enables a decrease in time-vs.-depth rates owing to increased running and operational speeds and a reduction in remediation activities as a result of increased reliability. The metal-to-metal and redundant elastomeric sealing and anchoring ELH technologies assist with both increased efficiency for current operations and the ability to push the industry's technological envelope.
The electrical submersible pump’s (ESP) impact on wellbore temperatures and integrity is seldom discussed in literature. Most literature discusses ESP run life and failure. The ESP heat dissipation increases the wellbore temperatures. Therefore, direct and indirect thermal-induced stresses are applied to the casings and tubing. At the same time, the trapped annular pressure buildup (APB) also increases, thereby applying additional stress on the casings and tubing. This raises the question—is the safety factor still valid? This is crucial in high-temperature/high-pressure (HT/HP) and deepwater/ultra-deepwater wells that have narrow design margins.
This paper presents studies on the prediction of wellbore temperature and pressure profiles, which account for the ESP heat dissipation effect on APB. The heat dissipation from the ESP electric motor, pump, and cable are considered. Then, the convective and conductive heat transfer through the wellbore are described in a transient wellbore temperature model. The updated temperature profile is then applied, and the APB and tubular stress analysis is revisited.
The model is integrated into an advanced casing and tubing design software platform. Case study results show increasing temperatures along the wellbore. The increased temperatures induce the APB and the strings axial compressive stress increase. In the studied case, the APB increased up to 23.6%. The increased APB induced additional loads on the tubing and casings, which can result in collapse/burst failures. Both theoretical analysis and case studies show that if the original design did not consider the use of ESP, induced APB can cause casing/tubing failure and result in wellbore integrity issues.
The findings indicate ESP heat dissipation does affect the wellbore integrity. Attention should be paid to the possible allocation of ESP in the future to achieve an accurate APB prediction during the modern wellbore completion design and planning phase. The findings are of particular interest in production monitoring and control, wellbore completion, ESP selection, casing/tubing design, and wellbore integrity, especially for mature-field and offshore wells.
The electro-hydraulic firing head features a novel combination of electronic control over a hydraulic firing mechanism. An electronics module senses wellbore pressure and, upon seeing a distinct signal, opens a valve that allows downhole pressure to operate a hydraulic firing mechanism. The hydraulic firing mechanism is extremely reliable, does not have sufficient energy to fire until safely downhole, and is immune to electromagnetic interference. The electronic control system prevents inadvertent pressure applications from prematurely activating the firing head. This combination of electronic control and hydraulic firing in a firing head offers unique and distinct benefits in safety, operational flexibility, and risk reduction.
On a recent job, a TCP assembly with dual electro-hydraulic firing heads (stacked vertically for redundancy) was run below a permanent packer and isolation valve. The electro-hydraulic firing head enabled this deployment to be conducted safely, with reduced risk of NPT, and in a single trip. A hydraulic firing head could not be used in this application due to the risk of pressure communication through the isolation valve during packer setting and testing. The TCP assembly was hung off the packer with a ballistically actuated automatic release. The electro-hydraulic firing head has a detonating cord bypass, allowing it to detonate guns below at the same time as actuating the release above. The availability of this firing head allowed this job to be performed more safely, more efficiently, and with reduced risk of NPT than was previously possible.
This paper will present an overview of the design and features of the electro-hydraulic firing head, discuss the recent successes in utilizing its unique abilities to enable more efficient job plans, and discuss other unique applications for this technology.