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You must log in to edit PetroWiki. Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. A pumpable plug with flexible cup-like extensions that seal and isolate the fluid behind the plug from the fluid in front.
Casing design for oil and gas wells continues to evolve to adapt to increasing challenges. The casing program of most wells represents a significant portion of the total well cost, between approximately 15 and 35%. This paper discusses how expandable liner hanger (ELH) technology continues to evolve to meet the needs of an operator with a new thick walled casing design in fields with H2S and CO2. Circumstances are described wherein thick wall casing design was necessary (greater collapse pressure and room for production safety valves). Details are presented describing why the ELH was selected, challenges encountered, development of a new liner hanger to fit the smaller thick-walled casing inside diameter (ID), and how the liner hanger running tool was modified to work inside a smaller casing. Prejob analysis that was performed to help reduce risks while running in hole (RIH) is discussed. Also highlighted are improved procedures, torque and drag simulations, surge and swab simulation, and critical well review exercises.
The operator chose a well design using 10 3/4 in. casing for a larger inside diameter (ID) installation of an arrangement using double electric submersible pumping (DESP). Casing weight of 79.2 ppf was selected to support the pressure load during well production. The ELH system complemented the new heavy wall casing design during construction and installation because of the many benefits it provided, such as high torque, washing and reaming, and multiple setting contingencies. Suitable expandable material was selected for the H2S and CO2 well environment. Two ELHs were used to run into 10 3/4 and 13 5/8 in. casing, 7 5/8- and 10 3/4-in. in liner through a sidetrack with deviation of more than 75° at the bottom, overcoming entrapment issues during the operation, and reaching total depth (TD). The cementing operation was executed successfully and the ELH expanded, leading to a successful operation with zero health, safety, and environment (HSE) or service quality issues. This paper discusses the latest ongoing developments in ELH technology applied using a new casing size and weight during the construction of oil and gas wells with sour service requirements.
Extended reach drilling (ERD) wells provide challenges in achieving successful liner hanger installations and liner cement jobs. This paper reviews successful expandable liner hanger (ELH) installations in challenging ERD wells in offshore North Sea and discusses how the metal-to-metal sealing ELH provides a solution to these challenges.
The paper discusses the advantages of the new ELH design, which adds metal-to-metal sealing technology to the existing proven elastomer-sealing technology. In addition, the new design offers improved ELH anchor capability. The paper also describes how the new features of this ELH design provide consistent results to meet the challenges of ERD wells. The paper also examines case histories of four metal-to-metal sealing ELHs set successfully in ERD wells in the North Sea since May 2015.
The metal-to-metal sealing technology of the new ELH design
This paper presents technical information to increase industry awareness of an additional ELH technology. Because ERD wells are becoming more prevalent, solutions are needed that provide improved reliability, increased operational capabilities, and the ability to provide a quality cement job in a challenging application. The metal-to-metal ELH provides the industry with additional technologies to meet these requirements to successfully drill extended-reach wells.
Drillout optimization is analyzed based on criteria that includes higher rate of penetration (ROP), reduced overall cost per foot, reduced drilling time, and reduced wear rates. In the industry, there are no mechanistic and empirical models used to simulate shoe track drillout optimization. The current common approach is the use of "best practices," which have been developed by companies throughout years of experience. However, even when the best practices are used, shoe track drillout is often time-consuming and damaging to the operation of the drilling tools.
This paper presents analyses of field shoe track drillouts data, obtained from several wells, to assess the primary drilling controlling parameters with respect to drillout times.
The study reveals primary factors that affect shoe track drillout time. It also provides an understanding of how operational parameters should be manipulated to achieve the desired ROP. Finally, the study results were compared to existing best practices. This comparison was used to create a combined list of recommendations that can be consulted before drilling through a shoe track. Although the elimination of damage to the BHA is an important issue in this topic, it is beyond the scope of this paper and may be the focus of future research.
Stage tools have been commonly used in North America for monobore completions to optimize economics. By cementing back the vertical and build sections of the wellbore, the requirement of the intermediate casing and liner hanger packer can be eliminated. An operator working in the K-1 carbonate formations of a massive field in eastern Saudi Arabia was examining a unique application of a stage tool to effectively cement and isolate a water-producing build section of a sidetracked lateral wellbore. The well incorporated a liner hanger packer with a multistage completion system. This paper will describe the distinct operational challenges encountered and how they were solved by redesigning an existing stage tool.
The well profile and construction specified that the liner had to be hung above the sidetrack point. Therefore, it was critical that the sequential operation of running the lower completion string, setting the liner hanger, releasing the liner hanger running tool, setting the open hole packers, cementing the upper liner section and then setting the top packer be completed with tremendous accuracy for a successful job. The operator selected a stage tool with a secondary contingency closure mechanism that did not limit the inside diameter through the system. This mechanism would ensure that all stages could still be stimulated if the secondary closure option was required. The use of the stage tool with a liner hanger system required some design modifications; the typical single foam plug, used to displace cement and close the tool in the standard version of the stage tool, was not an option. Instead, the operator required that a separate drill pipe dart and wiper plug assembly be used to displace cement through the drill pipe and the liner. The stage tool was, therefore, redesigned to close with a wiper plug launched from below the liner hanger packer.
After open hole conditioning, reaming and logging, the lower completion was run to setting depth and all equipment functioned without any issues. The problematic water producing zone was cemented and isolated and the stage tool was closed without the need to use the secondary closure mechanism. The stage tool was then milled out, leaving the well ready for stimulation. The redesigned tool enabled the operator to effectively cement the upper wellbore with no inside diameter restriction for stimulation.
This paper highlights the first introduction of cementing stage tool technology in conjunction with a multistage completion system to an operator in Saudi Arabia and the tool redesign required for accommodating a liner hanger packer in the wellbore. This method could also be applied to any type of lower completion such as sand management screens, inflow control devices or in conjunction with slotted or solid liners as an off-bottom cementing application.
Well cementing is a crucial component of deepwater well construction, and a key to cementing success is the performance of the cementing plug. Plug performance is primarily based on the mechanical wiping efficiency and wear resistance of the plug. However, limited understanding of the performance has hindered the establishment of standards. While API RP10F provides recommended testing practices to evaluate the performance of cementing float equipment, it does not include cementing plugs.
This paper is the first published review of efforts to better understand cement plug performance and to establish industry standards. Through laboratory studies, it examines material loss in actual deepwater applications and evaluates the effect on wiping performance of cementing plugs. These studies provide the basis of a selection process for wear-resistant materials. The paper also examines methods of measuring wiping efficiency and overall plug performance. Based on these methods, a proposal is presented for establishing industry performance standards for setting cementing plugs.
Cementing wiper plugs provide a physical barrier to cement contamination by separating displacement fluid and wiping residual mud film and other materials from the inside surface of the pipe. Separation and wiping efficiency are directly related to plug wear resistance and to the process of balancing design to achieve optimal stiffness and pressure containment. This design balance is achieved through rigorous material testing and design refinement. Analysis of wiper cuttings samples has provided a clear understanding of the plug's ability to provide a physical barrier to separate fluids and how that affects the function of downhole tools. This cuttings evaluation has provided information on material loss and positive fin interference. Results of the evaluation are corroborated by field performance achieved in cementing lengths of casing greater than 16,000 ft.
Plug wear is of particular concern in long, high-volume, deepwater casing strings where it can lead to displacement errors and reliability problems for downhole pressure-actuated tools. These displacement errors are examined in field applications that precisely locate the plug at multiple points during the cementing process.
Operators in the Cardium formation of central Alberta are increasingly adopting a cemented-back monobore well design to reduce costs and improve operational efficiency. Extensive field data from more than 360 wells completed by an operator working in this formation demonstrates the operational advantages and substantial cost savings gained by adopting a monobore well design. This paper details the evolution of well construction for open hole horizontals in the Cardium, and provides cost and operational comparisons between drilling different wellbore sizes, running different casing sizes, and using different stage tools to cement from the heel of the well back to surface.
The operator completed 77 wells in the Cardium using 177.8 mm intermediate casing through the build section and a 159 mm open hole lateral with 114.3 mm liner before evolving to a cemented-back monobore design. Analysis of the field data determined that 171 mm vertical and build sections of the wellbore, and a 159 mm open hole lateral with 114.3 mm casing is the optimal cemented-back monobore design, allowing for easier casing installation and providing substantial cost savings by eliminating the intermediate casing.
Monobore ball-drop completion systems require a stage tool to cement from the heel of the well back to surface. By implementing a stage collar that closes mechanically rather than with a wiper plug or dart, the operator was able to reduce wellbore integrity risks and considerably lower drill-out costs before stimulating the well. The operator has completed more than 220 wells using this stage collar with 100% success.
The geology of the upper formations was managed using invert drilling mud to control wellbore stability and downhole pressure, rather than intermediate casing, to successfully adopt a cemented-back monobore well design. The steps detailed in this paper to eliminate intermediate casing from wellbore construction, identify optimal wellbore sizes and reduce drill-out costs have proven to be successful in the field and can be applied to a variety of formations around the world.
Accessing unconventional reservoirs in the Cardium formation was made possible by advances in horizontal drilling and hydraulic fracturing. As a result, the Cardium of central Alberta has become one of Canada’s most active light oil plays. According to data pulled from the Canadian Discovery Well Completions & Frac Database in June 2014, there were only 37 horizontal and deviated wells drilled into the formation in 2008. Activity increased dramatically in the following years, with horizontal drilling peaking in 2011 and 2012 when operators drilled 861 and 863 wells, respectively.
Sheikh Veisi, Mahdi (Schlumberger) | Salehpour, Amir Gheisar (Schlumberger) | Wedhaswari, Victoria (Schlumberger) | Neto Bianchi, Nilo (Schlumberger) | Panjaitan, Reinhard Aberson (Total E&P Indonesia)
Cementation of the monobore 3 ½” and 4 ½” completion strings for TOTAL in Tunu field of Indonesia is a balancing act. The bottom most reservoir sands are within 10 m of a high pressure zone. Therefore having a conventional length of shoe track, 1 to 3 tubing joints, will block the access to the bottom sands. Furthermore, any error in displacement volumes of these cement jobs would lead to costly remediation. Drilling out cement inside the small tubing sizes would force TOTAL to use special drilling techniques, while displacing extra mud volumes would wet the shoe which could jeopardize the well integrity. To tackle the challenges, shoe track was eliminated with the float shoe and collar placed only 1m apart. A custom made calibration plug, with proper burst disc pressure rating, was designed and used prior to cementation that allowed the tubing volume to be measured physically. Based on observing the pressure spikes on the rig floor, the displacement volumes for all the cement jobs are known prior to the cement job. Application All completion strings cementations with reservoir targets close to tubing shoe. Results, Observation, and Conclusions Calibration plugs are used in more than 100 wells with the total depths of 4000m to 5000. The cement displacement is done accurately and top plug is bumped successfully. This is saving 30 m extra, the conventional shoe track length, drilling on each well. Also it contributes to the safe exploitation of the bottom targets without encountering the high pressure zones.
As it is proven to be valuable, this innovative cementation method is used by TOTAL ever since. Technical Contributions 1)Maximizing production by accessing bottom reservoirs 2)Accurate tubing volume measurement in cementation operations 3)Introducing an innovative and reliable technique to eliminate the shoe track.
The method of anchoring a tieback casing string using cement has been well documented. Industry standards for installing a tieback casing string usually have called for placing cement around the outside of the tieback casing string to provide a barrier against the potential of sustained surface casing pressure (SCP). The cement also is used to anchor the tieback casing string into the polished-bore receptacle during production. After cementing the tieback casing string, a cleanout trip is required to clean the inside diameter of the casing and to remove the landing collar and cementing wiper plugs.
A recent application in deepwater Gulf of Mexico (GOM) allowed a major oil and gas company to perform a step change in technology that enabled the operator to perform the function more rapidly and at reduced expense. Swellable packers were used instead of cement, providing a novel, cost-saving and risk-reducing approach.
This paper will discuss the use of swellable technology as an alternative method for anchoring a tieback casing string. This concept allows the operator to isolate potential downhole pressure away from the surface and to anchor the tieback casing string during production. By using swellable technology, no cleanout trip is required, which provides a substantial cost savings for deepwater operations. The unique approach also reduces the risk to the casing and drilling string from the removal of the cementing wiper plugs and the landing collar. The case history will provide the details of the new application and how it improved cost efficiency and enhanced operational safety.
Successfully installing a tieback casing string in deepwater operations can pose significant challenges for the operators and service companies. One of these challenges concerns the difficulty in obtaining and maintaining a pressure seal between the tieback seal assembly and the liner polished-bore receptacle (PBR), after the cementing operation is completed and during the production phase.
The industry-accepted practice has called for cementing the tieback casing string in place by circulating cement between the tieback casing annulus and the intermediate casing string while the tieback seal assembly is above the PBR.
(See Fig. 1). Once the cement is in place, the entire tieback casing string is then lowered, thereby inserting the seal assembly into the PBR. This operation must be completed while the cement in the annulus is still in a liquid state, and the effective seal must be verified before the cement hardens!
Another issue with cementing the tieback casing string is that normally only a small amount of cement is used to "tack cement?? the casing and seal assembly in place. When using only small amounts of cement, there is the possibility for the cement to become contaminated during placement, which results in a decrease in the effectiveness of the cement.
Once the cement is in place, the downhole hydraulics of the well will change, which in turn, will change the hook-load weight of the entire tieback casing string. This creates difficulties in getting the seal assembly fully inserted into the PBR so that a competent seal can be created.
When a cementing wiper plug is used during the cementing portion of the tieback casing operation, the wiper plug restricts the performance of a pressure test on the seal assembly once the tieback casing string has been lowered into the PBR (Fig. 2).