For many years, standard invert emulsion fluid (IEF) has been used to construct wells in the Sub-Andean basins in Bolivia because of the benefits to wellbore stability and its resilience in high-pressure/high-temperature (HP/HT) environments-it is becoming the best available option for drilling deep HP/HT wells in this region. Nevertheless, the construction of long sections with a narrow margin between pore pressure and fracture gradient combined with challenging well geometries and surface equipment limitations require a fluid capable of achieving the programmed high density values with an optimized rheology profile.
To address these challenges, a tailored organophilic clay-free IEF was engineered to achieve balance between low rheology, hole cleaning, and weighting material suspension at high temperature and highly deviated wellbore conditions.
Following the success of this first well [reaching 6100 m measured depth (MD)], this case study reached a depth of 6802 m MD/6612 m true vertical depth (TVD), the longest and second deepest well in Bolivia, with a main wellbore section of 5197 m comprised of 7 5/8-in. casing, 1279 m of 5-in. liner, and 326 m of 4 1/8-in. open hole. Operational drilling parameters within standard rig pumping capabilities were properly maintained during the drilling process.
The primary challenge encountered in this well was to achieve effective hole cleaning with controlled equivalent circulating density (ECD) values with a challenging directional program. Optimized flow rates and fluid rheology allowed for effective drilling and solids removal in the highly deviated well (47°) in +350°F environment with a 1.98 to 2.07 specific gravity (SG) fluid. Operational logs for pressure, drilling rate, and fluid properties for the deep, narrow-margin well are presented relative to those obtained for the offset wells using conventional IEF.
Using the novel low ECD drilling fluid represents a proven system for expanding drilling capabilities in deep, narrow wellbores whereby conventional fluid systems would be operationally limited in reaching project objectives. Applying proprietary hydraulic modeling and maintaining continuous laboratory support were important for project success.
Four wells were successfully drilled and completed, but high drilling fluid densities (1.95 to 1.98 SG) were necessary to maintain wellbore stability in the overburden section immediately above the depleted reservoir. The estimated hydrostatic overbalance from the drilling fluid was approximately 800 bar (11,603 psi) higher than reservoir pressure. A wellbore strengthening technique was selected to seal the calculated 1500 μm fractures induced by these high pressures. This paper highlights the engineering, logistical, and operational challenges encountered while successfully drilling and completing such wells.
Geomechanical data was initially acquired, including Young's modulus, Poisson's ratio, and minimum in-situ horizontal stress; and, together with the operational parameters [hole diameter and equivalent circulating density (ECD)], these data were used to estimate fracture width (1500 μm). Subsequently, a drilling fluid system was engineered and customized to seal such fractures, thereby strengthening the wellbore to help minimize losses in the reservoir. The solution was validated at two separate laboratories. Large particulate materials with a D50 of 600 to 2300 μm were used. Improvement opportunities during execution were captured for the next cycle.
A total drilling fluid loss of 512 m3 during a 16-hour period was experienced in one well after a drilling liner packoff occurred, and fractures greater than 1500 μm were initiated; however, the liner was successfully cemented in place. The coarse particulate materials (600 to 2300 μm) were mobilized in 500 and 1000 kg bags to minimize deck space requirements on the rig and help facilitate ease of mixing. Rig mixing and pit agitation capacity were important for effective mixing of the fluid system. The application also provided the opportunity to align testing procedures and equipment between the field and laboratory. With increasing reservoir depletion, the potential exists for fracture width increases that can impact the particle size of materials necessary to effectively design a solution. Engineered particulate solutions provided a pathway for sourcing and procuring the necessary wellbore strengthening materials.
Casing centralization and reciprocation during a cementing operation can help improve the efficiency of annular mud displacement and provide a basis for analyzing the percentage of mud displacement efficiency. This information is necessary when developing a mitigation plan for any cementing operation's risk assessment when centralization and pipe movement are considered as operational variables.
A state-of-the-art, three-dimensional (3D) finite displacement efficiency simulator analyzes the percentage of mud displacement efficiency when these four main possible scenarios are considered: low, medium, and high centralization and casing reciprocation during the cementing operation. This paper discusses three case studies validated by a risk assessment process developed during the cementing job design stage in which higher standoff and casing reciprocation suggest improved mud displacement efficiency and low fluid channeling when the cementing operation is finished. Cement bond log (CBL) results are discussed and shared when high standoff and casing reciprocation scenarios are considered.
Results of this study include the following observations and conclusions: Casing reciprocation helps improve displacement efficiency, which can provide improved cement bonding. If casing reciprocation movement is not possible, high casing centralization standoff can be an effective design technique because it can be used to enhance mud displacement efficiency in cementing operations. Wellbore stability is not compromised by equivalent circulating density (ECD) increments resulting from the reduction of annular clear space when using centralizers. Design risk assessment should include a comparative scenario analysis to mitigate the potential risk of poor mud displacement efficiency when considering casing centralization with medium to high standoff and casing reciprocation. At some point, casing reciprocation will not be a factor of improvement for mud displacement efficiency when sufficient standoff is considered for cementing operation designs. This scenario can help mitigate any likelihood of poor mud displacement efficiency if the casing is not reciprocated because of operational factors. Even though high casing standoff yields high percent displacement efficiency, it is recommended to follow the primary cementing operation's field practices as discussed.
Casing reciprocation helps improve displacement efficiency, which can provide improved cement bonding.
If casing reciprocation movement is not possible, high casing centralization standoff can be an effective design technique because it can be used to enhance mud displacement efficiency in cementing operations. Wellbore stability is not compromised by equivalent circulating density (ECD) increments resulting from the reduction of annular clear space when using centralizers.
Design risk assessment should include a comparative scenario analysis to mitigate the potential risk of poor mud displacement efficiency when considering casing centralization with medium to high standoff and casing reciprocation.
At some point, casing reciprocation will not be a factor of improvement for mud displacement efficiency when sufficient standoff is considered for cementing operation designs. This scenario can help mitigate any likelihood of poor mud displacement efficiency if the casing is not reciprocated because of operational factors.
Even though high casing standoff yields high percent displacement efficiency, it is recommended to follow the primary cementing operation's field practices as discussed.
A comprehensive practical analysis to prepare a cementing risk assessment included in an operation's program is reviewed. It considers low and high casing centralization as well as pipe movement as variables to help improve cement placement.
A major operator manages multiple, multiwell deep water projects in West Africa. For two such projects in Congo and Nigeria, it was determined that sand control was necessary and a stand-alone screen (SAS) completion was an efficient and cost-effective means for providing sand control for the majority of wells in both projects. This paper describes a new and unique feature of the SAS completion, called the Dual-Isolation Assembly (DIA), which addresses many challenges, and its application in Nigeria on the Egina Project.
Standard SAS completions incorporate a circulation path down the workstring, through the float shoe, and back to surface through the workstring by casing annulus for circulation, pressure maintenance, and removal of the filter cake at the operation's conclusion. The capability to wash down through the toe of the system while running in the well requires washpipe seals inside the float shoe, which incorporates spring-loaded valves that open during pumping, but close when pumping stops. In addition to the wash-down capability, the washpipe incorporates a shifter for closing an uphole isolation valve with the ability to reopen the valve, if necessary.
For an injector well, the flow path into the formation is through the sand-control screens and float shoe from the inside. The path is the opposite for a producer well, which flows from the formation to inside the screen while the float shoe is closed. Because of the different natures of the flow paths, the float shoe is continuously exercised in an injector well as a result of injection fluid starts and stops. During injection, if the opening pressure of the float shoe spring is exceeded, it could stay open over time, causing loss of integrity of the float shoe. When pumping stops, the flow path into the screen through the float shoe could heave formation particles back into the wellbore, as a result of the reservoir being energized upon injection shutdown. The DIA provides secondary and permanent isolation of the float shoe, as requested by the operator, and is capable of shifting a barrier isolation valve installed in the lower completion to comply with the operator's barrier policy for deepwater wells. The DIA and lower completion design allows the operator to safely place a filter-cake breaker treatment in the open hole after setting a lower completion packer.
In addition to fulfilling the requirements of these SAS completions, the DIA design addresses other potential challenges, such as hydraulic locks and any potential swabbing while manipulating the service tools. This paper describes the evolution of the DIA design and full QA/QC and operational procedures, which led to the successful deployment and excellent functionality of the DIA in 12 completions run to date in Nigeria.
This paper identifies restimulation opportunities in existing multistage completed horizontal wells with plans for a customized refracturing solution applying breakthrough stimulation and diversion processes to increase oil production in a tight carbonate formation, offshore Black Sea. Because operators are shifting strategy in a low oil price environment from new well drilling toward well interventions, refracturing is gaining more focus, particularly for tight and less conventional reservoirs. Many potential candidates also have suboptimal completions for refracturing, so the challenge for operators is selecting the best candidates and designing a refracturing treatment for improved well performance in these complex situations. This paper describes the well screening and selection process for the restimulation of existing horizontal wells with multistage openhole completions.
During Phase 1 of the project, pilot candidates were ranked using a weighted average score of specific decision criteria for evaluating the refracturing potential. The goal of the screening process was to identify wellbores with the most bypassed reserves and to determine the root cause. Top candidates demonstrated bypassed reserve potential because of large completion spacing and lower average permeability than was originally estimated. The design process emphasized identifying areas where incremental oil could be accessed by substantially increasing total exposed conductive surface area and placing new fractures between existing using novel approaches to refracturing incorporating flow diverting technology. The application of an engineered pressure-managed design approach optimized proppant cycles, and flow diverting refracturing methods were a fundamental component in recognizing that the restimulation pilot was realistic, achievable, and justified economically. By dynamically managing and adapting proppant schedules, diverter volume fractions, and total materials pumped over time, new induced fracture surface areas can be reliably created in the most economic manner.
Phase 2 consisted of executing the refracturing operation on the selected pilot well, which had been originally hydraulically fractured in 2009. A repressurization procedure of the reservoir was performed before the main treatment to equalize pressure depletion along the lateral and ultimately enhance the coverage of newly fractured zones along the wellbore. The refracturing treatment on the pilot well consisted of four proppant cycles with application of engineered pressure management to improve fracture initiations and flow distribution. A degradable particulate diverter technology was used as primary isolation of each fracturing cycle.
Restimulation results of the pilot well demonstrated technical and production success, with huge potential to implement this technology during the next phase of field revitalization (Phase 3). This pilot project has proved that the combination of a well selection process aimed at finding unstimulated and bypassed reservoir volume and the application of customized technical solutions for refracturing can be successfully applied to increase recovery factors and identify new opportunities in mature field redevelopment.
Lunney, Iain (Halliburton) | Thompson, John (Halliburton) | Wilkes, John (Halliburton) | Chong, Matthew (Halliburton) | Whyte, Iain (Tullow Oil) | Peytchev, Peter (Tullow Oil) | Mawuli, Elike (Tullow Oil) | Goel, Pulkit (Tullow Oil) | Burns, John (Tullow Oil)
In the budgeting of all major development projects, there is always a desire to capture the financial and operational opportunities of all new and existing technologies; however, this can be difficult if not proven to be viable in advance of the development campaign commencing. This leads to great difficulty in fully capturing potential savings in future financial planning. In a cost-sensitive market, a leading East Africa exploration and production operator recognized an opportunity to trial new technologies in the exploration and appraisal campaign phase in order to reduce well cost and risk, which could be directly translated to the development campaign feasibility model. A flat-time analysis was performed on historical data to benchmark the connection performance against relevant proxies. From this analysis, it was determined that there was room for improvement from both technology and existing practices. To improve the connection time on a technology basis, offset field resistivity data were modelled to determine the feasibility of the formations drilled to efficiently propagate a bi-directional electromagnetic signal. Once the modelled feasibility was deemed acceptable to deploy from a risk perspective, a systematic field-trial plan was developed to deliver proof of concept, which was followed by the second element, running the system to reduce connection time. After two successful proof-of-concept runs, the electromagnetic system facilitated a material reduction in connection time, which could then be applied to the development project economics. Whilst primarily focusing on technology-oriented connection improvements, there was also a systematic performance improvement from the human element on the rig floor owing to the performance initiative. The secondary benefit of successfully implementing the electromagnetic telemetry system was the increased data rate and the ability to transmit annular pressure data while the pumps were off, which provides valuable data to understand wellbore hydraulic behavior during pumps-off events. With conventional mud-pulse telemetry systems, the critical path is impeded to obtain these measurements, where annular pressure data is streamed to surface after the surface event (e.g., LOT / FIT, connection ballooning check, etc.). During these field trials, the downhole equipment complexity run in conjunction with the electromagnetic telemetry transitioned from basic gamma ray and pressure measurements to a quad-combo LWD string run in conjunction with a rotary steerable system.
An oil and gas operator in the Gulf of Mexico (GOM) planned to drill a deepwater well section in one run by concurrently drilling and enlarging a 12¼- to 14½-in. hole while deviating from 60 to 30° inclination and crossing expected depleted formations. At section total depth (TD), the rathole below the underreamer needed to be eliminated to help ensure successful cementing of the liner. A bottomhole assembly (BHA) was designed to allow achieving these objectives in one run, and the field results obtained with the system are described.
The first step in determining the best BHA design was to compile drilling experiences through the target formations and perform a review of all pertinent offset-well information. Weaker zones had been encountered in the 12¼ × 14½-in. section, and an at-bit reamer (ABR) had to be included in the BHA to allow the liner to be set on the bottom of the section, rather than leaving an 85- to 135-ft rathole. Because the ABR placement in the BHA is between the bit and the rotary-steerable-system (RSS) tool, it was important to ensure that directional control could be maintained in the section and make certain no interference existed between the ABR and the wellbore that could compromise control. Stabilization and placement of the underreamer were also crucial to ensure that the necessary directional performance was obtained without overstressing the BHA components, and modeling was performed to optimize the design. Hydraulics and torque-and-drag modeling ensured that the BHA design could drill the depleted zone without premature activation of either reamer.
The modeling and analysis of offset performance resulted in successfully drilling the section and opening the rathole in one run. The BHA was steered to the final desired angle, and reached the section TD without incident and at the desired rate of penetration (ROP). After the section TD was reached, the ABR successfully opened the 12¼-in. rathole to the desired 14 in., allowing the liner to be set 3 ft from the bottom. Normally, this type of operation would require a separate dedicated hole-opening run. Using the new design eliminated the additional trip and the time necessary to open the hole, which was estimated at 56 hours.
A BHA solution was developed through modeling that allowed the operator to not only maintain the steerability needed to achieve directional requirements with an ABR between the bit and the RSS while drilling depleted formations but also to concurrently perform underreaming.
Zhang, Feifei (Yangtze University) | Kang, Yongfeng (Halliburton) | Wang, Zhaoyang (Halliburton) | Miska, Stefan (University of Tulsa) | Yu, Mengjiao (University of Tulsa) | Zamanipour, Zahra (University of Tulsa)
This paper identifies wellbore-stability concerns caused by transient swab/surge pressures during deepwater-drilling tripping and reaming operations. Wellbore-stability analysis that couples transient swab/surge wellbore-pressure oscillations and in-situ-stress field oscillations in the near-wellbore (NWB) zone in deepwater drilling is presented.
A transient swab/surge model is developed by considering drillstring components, wellbore structure, formation elasticity, pipe elasticity, fluid compressibility, fluid rheology, and the flow between wellbore and formation. Real-time pressure oscillations during tripping/reaming are obtained. On the basis of geomechanical principles, in-situ stress around the wellbore is calculated by coupling transient wellbore pressure with swab/surge 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 work flow is proposed to obtain the safe-operating window for tripping and reaming processes. On the basis of 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 frictional pressure loss during the normal-circulation process. With the effect of swab/surge pressure, the safe-operating window can become narrower than expected. The induced pore pressure decreases monotonically as the radial distance increases, and it is limited only to the NWB region and dissipates within one to two hole diameters away from the wellbore.
This study provides insight into the integration of wellbore-stability analysis and transient swab/surge-pressure analysis, which is discussed rarely in the literature. It indicates that tripping-induced transient-stress and pore-pressure changes can place important impacts on the effective-stress clouds for the NWB region, which affect the wellbore-stability status significantly.
This paper investigates stress and strain distributions determined through finite-element analysis (FEA) simulation and three-dimensional (3-D), digital image correlation (DIC) measurements obtained during full-scale testing of a Technology Advancement of Multilaterals (TAML) Level 5 multilateral junction prototype subjected to high internal pressure.
A multilateral well consists of one main wellbore with one or more lateral wellbores drilled from the main wellbore. The point at which a lateral is drilled from the main wellbore is identified as the wellbore junction. The wellbore junction's integrity is important to the success of the multilateral well construction (
This study discusses a completion system TAML Level 5 multilateral junction subjected to a qualification program, including internal and external pressure cycles with the junction in a deployed position to verify pressure integrity. The junction was evaluated through both numerical simulation and full-scale physical testing of a prototype, which was designed to be run in 10-3/4-in., 65.7-lb casing with a 5-1/2-in. lateral leg and a 3-1/2-in. mainbore leg.
This paper investigates stress and strain distributions determined through FEA simulation and 3-D DIC measurements obtained during full-scale testing of a junction at 6,000-psi internal pressure. Although DIC has been widely used for strain measurements within the industry, it was introduced into the junction-test program to meet increasingly challenging environments. Compared to conventional strain-gauge measurements, DIC allows for full-field strain measurements, including points at which complex geometries exist, such as the external intersection of the main and lateral legs, which is commonly the critical area with high stress concentrations. A correlation and comparison between the numerical simulation and DIC measurements are discussed to qualitatively validate the FEA model with experimental results.
The petroleum industry requires more advanced technologies as wells are drilled in more challenging environments (i.e., deep sea, artic environments, higher pressures, etc.). To provide these advanced technologies, engineers need the capability to help ensure their designs meet the requirements of such challenging environments. DIC provides a means to qualitatively validate the numerical simulations for complex designs.
The first intelligent completion was deployed in the Snorre field offshore Norway in August 1997, marking a major milestone for advanced completion engineering, reservoir insight, and production control. For the first time, an operator could manipulate tubing outflow performance at, or near, the sandface inflow node, without intervention or workover, but rather live via remote control using an interval control valve (ICV). Twenty years later, technological advancements have significantly increased the reliability and capability of intelligent completion tools with applications in ultra-deepwater, mature fields, as well as in the cost-sensitive unconventional arena.
This paper discusses the significant technological advancements and reliability of ICVs by comparing the following: case history examples of technology, applications, and installations from the past and present; associated technological and operation challenges with solutions and resulting reliability increases; and a view of the future design and reliability aspects of ICVs with respect to hydraulic vs. electric control and actuation. ICV case history examples are discussed below:
Comparing two field-wide offshore deepwater Africa campaigns in 2007 and 2015 with respect to ICV reliability, operational improvements, and technology from eight years of continuous improvement. Using a remotely operated hydraulic ICV installed above the production packer as a circulating device and a gas-tight barrier. This ICV was actuated through pressure signals to a battery-operated control module and micro-hydraulic pump vs. control lines to surface. History of ICVs installed as part of the mature fields of the Middle East and why high-actuation force will always be a requirement. A current high rate water injection completion campaign as part of an offshore mature field in which ICV position sensors transmitting choke positions in real time have significantly increased the operator's confidence of zonal-flow allocation. A Middle East operator's current application for low-cost ICVs. History of ICVs installed in multi-lateral completions and why they should stay in the motherbore.
Comparing two field-wide offshore deepwater Africa campaigns in 2007 and 2015 with respect to ICV reliability, operational improvements, and technology from eight years of continuous improvement.
Using a remotely operated hydraulic ICV installed above the production packer as a circulating device and a gas-tight barrier. This ICV was actuated through pressure signals to a battery-operated control module and micro-hydraulic pump vs. control lines to surface.
History of ICVs installed as part of the mature fields of the Middle East and why high-actuation force will always be a requirement.
A current high rate water injection completion campaign as part of an offshore mature field in which ICV position sensors transmitting choke positions in real time have significantly increased the operator's confidence of zonal-flow allocation.
A Middle East operator's current application for low-cost ICVs.
History of ICVs installed in multi-lateral completions and why they should stay in the motherbore.
The steady increase in ICV reliability is the result of advancing technology, as well as continuous improvement in operational procedures. These case histories help detail each advancement.
The future of intelligent completions and ICVs is tied to precision of device control, system reliability assurance, and effective use of sensor data to generate recognizable value. Precision and data require electronic control and transmission; however, hydraulic actuation offers more advantages with current available technology. This paper concludes with an argument for the future of practical ICV installation, zone control, actuation, and closed-loop operator interface.