EdVenture

Abstract The Haynesville organic shale has just under 3600 wells, completed before mid-2016, with cluster spacings over 50 feet. This wide spacing resulted in many wells having missed or bypassed reserve recovery due to inefficient completions. Understandably these wells would be prime candidates for refracturing. Refracs have the advantage of lower up-front capital cost, fewer operational issues that rely on functioning supply chains, and significantly lower carbon footprint than new wells that need to be drilled prior to completion. However, a frequent concern is that refracs in the Haynesville cannot compete with new well economics. We looked at both public and operator refrac data to identify the criteria that makes a good Haynesville refrac candidate. We offer case studies to show the economic performance of 45 Haynesville liner refracs using actual post refrac decline data and current well costs. Both the economic value of the post refrac production is included along with the economic value of protecting infill wells from asymmetric fractures. An analysis of the completion design for a typical Haynesville refrac is also provided to demonstrate that significant upside remains for improvement if "best practices" are applied. These include Extreme Limited Entry (XLE), zero-degree top perforations per cluster, larger diameter expandable liners, and microproppant in the prepad. In our data set, the typical Haynesville refrac completion has very low pressure drops (520 psi pre-erosion) across the perforations. With average treating pressures of 9500 psi there is limited room for higher pressure drops due to a 10,500-psi surface pressure limit. And so, the available delta pressure for treatment is limited to +/- 500 psi when a 2500 to 3000 psi pressure drop is recommended to maximize cluster efficiency (Hausveit 2020). With the author’s recommended practices, over 2500 psi of excess friction losses can be avoided, providing adequate margin to achieve the recommended pressure drop. With increased cluster efficiency, increased recovery factors should follow. While Haynesville refracs have successfully increased estimated ultimate recovery (EUR), when "best practices" are followed, the economic returns should be highly competitive with new-well completion economics. If the refracs had the 60% average cluster efficiency values from several studies done on poorly diverted treatments (Weddle 2018 and Miller 2011) the total NPV10 for a P50 refrac is equivalent to the new well NPV10 values.

Abstract As an enabling technology, solid expandable tubulars continue to revolutionize the design and construction of oil and gas wells. Although solid expandable systems are now widely accepted as a viable casing alternative, some operators do not apply the technology in their wells. Limited information regarding the tubulars' post-expansion performance properties creates uncertainty in the application of solid expandable tubulars. A better understanding of how the pipe properties are affected by the expansion process is imperative to optimizing the benefits of system application. Using American Petroleum Institute (API) performance equations on post-expanded tubulars do not clearly identify the limits of the pipe. Testing is underway to create accurate predictive models for expansion force and post-expansion collapse. These full-scale laboratory tests, using API methods where applicable, determine how the expansion process changes collapse resistance and residual stress. Pre and post expansion mechanical and material properties are analyzed using American Society for Testing and Materials (ASTM) methods. Testing for H2S and CO2 environments employ the NACE methods. This paper describes the testing procedures and results of the post-expansion performance property testing. These findings will be compared and contrasted to API standards for conventional pipe. In addition, the paper will discuss industry implications for determining solid expandable tubular standards.

Abstract Historically, operators used solid expandable tubulars as contingencies to mitigate unexpected hole problems, minimize loss of hole size and to meet project objectives. However, some operators quickly realized that by incorporating this technology into their initial field development and workover plans, previously untapped reserves could be brought online. An operator in India combined solid expandable tubulars with sidetracking operations to reach additional reserves with optimized hole size in several offshore wells. Sidetracking out of a milled window results in loss of hole size with consecutive casing strings bringing further reductions. In this common scenario, the operator could be faced with drilling the drain hole with slimhole tools that drastically reduce the flow area and limit logging and drilling equipment availability. Planning the application of solid expandables through the milled window in these vertical wells allowed the operator to economically extract previously unswept reserves. With conventional technology they were faced with exiting out of the 9-5/8 in. casing and setting 7 in. and 4-1/2 in. liners to isolate problematic and depleted zones above the pay zone. The pay zone would be drilled using 3-3/4 in. slimhole tool strings that placed restrictions in the outflow of the reservoir and compromised the workover program economics. This paper will discuss how the planned-in use of expandable tubulars enabled the operator to sidetrack and recomplete poor-producing vertical wells into horizontal wellbores. This approach allowed the operator to maintain optimum drain hole that resulted in a five-fold increase in daily oil production. The paper will describe the complimentary technologies used with the solid expandables and the lessons learned in the first two wells. The operator/contractor relationship will also be discussed regarding project management of multi-well workover programs for both offshore and onshore fields.

With over 750 installations worldwide, solid expandable tubular systems have gone from an evolutionary idea to a technology that delivers on its promise. Long touted as a technology that can help operators mitigate downhole challenges, expandable tubulars are now being applied as enabling systems in wellbore construction, in field development, for casing repair and remediation and for field-wide revitalization.The installation records for these systems are as wide as the application realm and exemplify the adaptable nature of the technology. This adaptability has led to the technology evolving from being used strictly as a drilling-problem solution to an integral wellbore component. Solid expandable systems have been used in a variety of environments, such as HTHP and ultra-deepwater projects, and for a myriad of conditions such as control of lost circulation zones, casing shoe extensions and isolation of unstable formations. In cased-hole situations, these systems have been used to isolate old perforated intervals or protect weak casing, replacing less reliable conventional squeeze cementing techniques. Solid expandable systems have helped operators reach and produce reserves that previously were unattainable due to drilling conditions and economic constraints, have provided flexibility for exploration-well uncertainties, and have reduced well costs with a slimmer well design.Case histories will demonstrate how solid expandable tubulars have delivered on the promise and potential as an enabling technology. Case histories to be included will describe how solid expandable systems have been successfully incorporated in a field-development project in Malaysia, a casing-repair project in China and as a vital component in a total drilling-management project in the Arabian Sea. This paper will also validate the economic viability of these systems as a contributive and reliable technology.

Abstract New and innovative technology has a way of significantly influencing peripheral products and processes. A case-in-point is the relationship between solid expandable tubulars and cementing practices. The early years of cementing expandable casing were filled with researchers working to develop novel chemistries and resourceful techniques for annular sealants that varied from modified conventional cements to highly-specialized non-Portland systems such as resins. Experience and time relegated many of these chemistries and systems to specific situations. Instead of needing atypical techniques and unique products, the more effective and applicable approach with solid expandables consisted of modified placement practices, training, logistics, and refined engineering of conventional cementing methods. But, as solid expandable tubulars are installed in deeper and higher-angled wells, annular sealant methods and products will be required to function in more extreme conditions. This paper will examine the evolution of cementing processes and products for solid expandable tubulars. Emphasis is placed on best practices and lessons learned, with the intent of giving the reader a practical field guide. Checklists for key slurry design issues and how they correlate with the job logistics of the expansion operation will be included. This paper will also discuss foreseeable application trends in expandable use and logical modifications and enhancements in cementing procedures, technology and chemistries.

Solid expandable tubular technology has seen an impressive uptake in recent years. The technology has the potential to reduce cost, increase production and give access to new reserves. In 2004/2005, Shell Malaysia Exploration & Production installed solid expandables in seven wells, putting itself at the forefront of the technology and adding significant value to the business.The design philosophy that has been adopted in Shell Malaysia can be described as:Use solid expandables as a planned-in contingency application in case the

Major operators are using solid expandable tubulars in existing wells to tap added reservoir pay. This use of the technology is the result of close collaboration between the contractor and the operator, particularly the reservoir engineering and drilling departments. Together they have devised plans that maximize the return-on-investment (ROI) and the long term sustainability of the reservoir.The use of solid expandable tubulars to provide a larger drainhole in existing wellbores is proving to be a considerable benefit to many operators. Aside from the obvious production gains from a larger borehole, the operator also gains on the drilling side of the equation. The larger inside diameter (ID) through the solid expandable casing allows for the use of larger drilling tools. These larger tools typically drill farther and faster than smaller tools and suffer far less non-productive time due to failures.This paper reviews the value derived from using solid expandable tubulars in the casing design of existing wells with actual case history data. Further, the paper details ancillary benefits that can be factored into the value gained by the operator.

Abstract The potential coupling of two leading-edge technologies has garnered much attention for its substantial business case regarding field development optimization. This specific application consists of marrying single-diameter technology and extended reach drilling (ERD). Using these two technologies as companion pieces in a drilling design can positively impact capital cost structure, resulting in economically superior alternative development scenarios. Single-diameter technology, a natural derivative of the conventional solid expandable tubular system, provides the foundation for a significant increase in the lateral reach of many extended-reach wellbores. This extended lateral reach results in increased reservoir contact that can lead to increased production per well. Increased lateral reach and production per well can ultimately reduce the required field well counts and infrastructure, resulting in improved field development economics. This paper will describe how combining these technologies mitigates critical factors that limit achievable reach including dogleg severity, casing openhole size vs. drillstring size, and ultimately torque and drag. Using solid expandable tubular single-diameter technology with significant friction reduction could extend the current ERD envelope 25 to 100%. More efficient reserves access, economic benefits and technical advantages will also be presented. In conclusion, this paper will discuss the technology's proven, simulated and engineered potential and how it can put more reserves within reach. Introduction Solid expandable tubulars have rapidly evolved over the last few years into a proven openhole drilling liner and cased-hole remedial liner alternative to conventional technology. These systems improve capital efficiency, reduce drilling trouble time, improve field development economics and extend lateral drilling reach, and/or perform extensive remedial work while preserving the required completion and/or completion size. The use of expandable technology has proven to be highly effective as a contingency and a planned well design application. The single-diameter system offers a truly enabling technology to complement the reliable and cost-effective solid expandable tubular applications. As part of the front-end engineering and design for a major North Sea operator, a well design feasibility study was conducted over an existing and planned field development. This study was conducted to assess the relative merits of applying conventional drilling technology versus expandable tubular technology regarding lateral reach and the impact on capital efficiency and potential field development. This welldesignmodeling study indicated potential lateral reachincreases of 25 to 100% with significantly reduced drilling trouble in both fields. Complementary drilling performance and cost studies have also indicated that existing and planned operator well costs and times in the same two North Sea fields can be reduced by over $40MM, or 30 to 50% of the current and forecast drilling cost and time, with the application of solid expandable tubulars and/or single-diameter technology. These well design studies also indicated preservation of desired completion size, which led the operator to conclude that planned subsea templates and associated infrastructure and/or satellite tie-ins can be eliminated from their field developments with solid expandable tubulars and/or singlediameter technology.

Narrow pore pressure/fracture gradient windows often necessitate additional casing strings to reach deeper objective depths. Operators are constrained by the number of strings of conventional casing that they can run through subsea or surface wellhead equipment. Planning solid expandable tubulars into the well design allows the operator to run additional casing strings and drill to deeper objectives.Using a solid expandable tubular system in the upper sections of the well design preserves hole size from the onset and allows more casing strings to be run without having to push casing points to the frac-gradient limit. Preserving hole size contributes to drilling efficiency, reduces equivalent circulation density (ECD), and minimizes risk associated with small hole size in deeper sections of the wellbore.Another application for solid expandable tubulars is with surface stack technology. Early surface stack systems were designed around a subsea stack blowout preventer (BOP) system placed on top of a 13-3/8 in. drilling riser. After setting the 13-3/8 in. riser, only one or two casing strings could be run through the riser, which precluded reaching deeper geologic objectives.This paper will look at two case histories. The first case history compares two deepwater offset wells in Mississippi Canyon. One well used expandable casing as a contingency, and the other well incorporated the casing as part of the base design. The second case history will evaluate a well where solid expandable tubular technology allowed up to three additional casing strings to be run in a surface stack application. This paper discusses how combining solid expandable tubular technology with surface stack technology has pushed the technical limits of surface stack drilling into deeper water and deeper formations.

During initial completion operations on a deepwater subsea oil well in the Gulf of Mexico, the 7-3/4 in., 46.1 lb/ft casing failed the pressure test in the production liner. Subsequent operations located the casing leak 1,800 ft above the target completion intervals. The original completion was planned to be a stacked, commingled frac pack with reservoir depths over 23,000 feet and pressures over 14,500 psi.To best address the problem and maintain the original well objectives, a solid expandable tubular system was selected to isolate the casing leak. The first expandable cased-hole liner run in the well failed to initiate expansion and was recovered. Reviews, lab mechanical tests and surface prototype tests were conducted to determine the cause of the unsuccessful start and to plan a second run for casing remediation. The revised design deviated from standard equipment and used a shorter launcher with a smaller outside diameter (OD) and a closed-ended system. In addition to the equipment modifications, lessons learned from the first attempt influenced procedural changes for the second installation.The second cased-hole liner run in the well a few weeks later was successfully installed and expanded. The ∼2,300 feet of expandable liner used eight elastomer seal anchor joints specifically located to isolate the leak and allow completion operations to resume essentially as planned. This installation was carried out with straightforward dimensional changes to the expansion system and revised procedures. The post-expansion dimensions of the liner enabled the completion of the well with a 7 in., 38 lb/ft equivalent inside diameter (ID) casing using standard completion equipment. At the time, this application set a record as the deepest cased-hole expandable liner ever run. The financial benefits of the installation included avoiding costs of drilling a risky sidetrack and production deferment.This paper will discuss the problem on the first installation attempt, the operational response, subsequent recovery, lab tests and surface trials. The second installation will be covered in detail with an overview of completion operations and a brief outline of the value added through this expandable liner solution.