Extended-Time Conductivity Testing of Proppants Used for Multi-Stage Horizontal Completions

The American Petroleum Institute Recommended Practice 19-D (2018) is the current industry standard for conductivity testing of proppants used in hydraulic fracturing. Similar to previous standards from both the API and ISO, it continues the practice of measuring a "reference" long-term conductivity after 50-hours of time at a given stress. The fracture design engineer is then left to estimate a damage factor to apply over the life of the well completion based on correlations or experience. This study takes four standard proppants used for multi-stage horizontal well completions in North America and presents test data over 250-days of "extended-time" at 7,500 psi of effective stress. The API RP 19-D procedure was followed for all testing, but extended for 250-days duration for the four proppant types: 40/70 mesh mono-crystalline "White" sand, 40/70 mesh multi-crystalline "Brown" sand, 100 mesh "Brown" sand, and 40/70 mesh Light Weight Ceramic (LWC). The 7,500 psi stress condition was chosen to replicate initial stress conditions for a 10,000 feet deep well with a 0.75 psi/ft fracture gradient - typical of unconventional resource plays such as the Bakken formation of North Dakota or the Delaware Basin in west Texas. Results presented provide a measure of the amount of damage occurring in the proppant pack due to time at stress. To the authors’ knowledge, there has never been any extended-time conductivity data published for multiple proppant types over the timeframe completed in this study - despite the obvious need for this understanding to optimize the stimulation design over the full life of the well. Results for the four proppant types are presented as conductivity curves as a function of time for the 250-days of testing. Pack degradation is shown to follow a semi-log decline. Late time continued degradation for all materials is extrapolated over the life of a typical well (40 years), and compared to extended-time particle size distribution and crush data to explain the results observed. Extended-time data such as this 250-day study have never been published on proppants such as these despite the fact that fracture conductivity has a major impact on the productive life of a well and the ultimate recovery of hydrocarbons from the formation. The data presented should be of great interest to any engineer involved with completion designs, or reservoir engineers assessing the productive life and ultimate recovery in the formation since economic optimization is primarily driven by the interplay of fracture length/area with extended-time in-situ fracture conductivity.

Ilmenite Inclusion: A Solution towards Solid Sagging for Hematite-Based Invert Emulsion Mud

The sagging tendency of hematite in drilling mud is a common challenge occurring at high-pressure and high-temperature (HP/HT) applications. This work studies the performance of hematite-based invert emulsion mud for HP/HT conditions and provides a solution to prevent the hematite settlement using a combination of ilmenite with hematite. Practical mud formulation was utilized over a range of ilmenite/hematite ratios (0/100, 20/80, 40/60, and 50/50%) to study sagging behaviour. From the sag tests, the optimum combination proportion was determined. Thereafter, the density, emulsion stability, rheological and viscoelastic properties, and filtration conduct for the formulated mud were evaluated. The experiments were conditioned as per the standards of the American Petroleum Institute. The obtained results of sagging experiments indicated that including 50% of ilmenite mitigated the hematite settling and reduced the sag tendency towards the safe range. A slight drop (4%) in mud weight was noticed upon adding the ilmenite, whereas the emulsion stability was enhanced from 551 to 574 volts with the 50% ilmenite content. The rheology and viscoelasticity measurements showed that 50/50% combination improved the yield point (YP) by 50% with a trivial 1 cP increment on plastic viscosity (PV), hence enhancing the YP/PV ratio by 46%. Also, the gelling strength was enhanced resulting in flat rheology and better gel structure. The filtration behaviour of 50% ilmenite mud was improved compared to blank hematite as it resulted in 21, 15, and 17% reduction on the filtrated volume, filter cake weight, and thickness, respectively. This study provides a solution for hematite sagging issue at HP/HT using combined weighting agents, which contributes to enhancing the mud stability and avoiding several well control issues and related operational and technical challenges that eventually will economize the drilling cost and time.

A New Viscosity and Density Sensing Platform for Drilling Automation

During drilling operations, measurements of drilling fluid/mud viscosity and density provide key information to ensure safe operations (e.g., maintain wellbore integrity) and improve the rate of penetration (e.g., maintain proper hole cleaning). Nowadays, these measurements are still performed manually by using a calibrated funnel viscometer and a weight balance, as stipulated by current American Petroleum Institute (API) standards. In this study, we introduce an automated viscosity/density measurement system based on an electromechanical tuning fork resonator. The system allows for continuous measurements as fast as several times per second in a compact footprint, allowing it to be deployed in tanks or pipelines and/or gathering data from multiple sensors in the mud circulation system. The streams of data produced were broadcasted to a nearby computer allowing for live monitoring of the viscosity and density. The results obtained by the in-tank system in five wells were in good agreement with the standard reference measurements from the mud logs. Here, we describe the development and testing of the tool as well as general guidelines for integration into a rig edge-computing system for real-time analytics and detection of operational problems and drilling automation.

API Process Safety Site Assessment Program PSSAP®: Significant Program Updates and Future Focus

The American Petroleum Institute (API) and the U.S. oil and natural gas industry have long been committed to protecting the health and safety of our workers, contractors and neighbors. For more the 75 years, API has led the development of industry standards, sharing lessons learned as well as the establishment of training and certification programs. In recent years, despite safety improvements by the refining industry, incidents have increased attention on process safety by industry, governments, non-government organizations (NGOs), and the media. Recognizing these concerns, API and our memebrs are working collectively to improve or develop new programs improve process safety performance. As part of the industry's ongoing commitment, API, in collaboration with industry partners, has developed a Process Safety Site Assessment Program (PSSAP®), an assessment program focused on evaluating higher risk activities in a refining, petrochemical, or chemical facility. This program is intended to: Promote process safety performance improvement industry wide; Promote learnings from industry practices; Provide benchmarking through the consistent use of industry-developed good practice protocols; Serve as a feedback mechanism for an analysis of industry performance; and, Encourage safety collaboration among participating sites and industry experts. PSSAP benchmarking, a key aspect of the program, allows sites to judge their performance against that of their peers in a blinded fashion. In addition to this benchmarking, the consistent use of our good-practice protocols enables API to analyze where companies may still be working to improve. Taking that information, API has implemented other programs to assist industry in those areas. Further, it has allowed API to quantify PSSAP protocol scoring improvements across the industry, seeing positive momentum in benchmarking scoring across the life of the program. PSSAP® is also a primary resource to support API Energy Excellence® implementation. API Energy Excellence is another critical API program in which all API members commit to enhance the integrity of operations across the industry by applying standards, implementing workforce training programs, and participating in performance initiatives. Downstream and petrochemical operators can use these PSSAP protocols to help demonstrate conformance to their API Energy Excellence requirements. PSSAP® is flexible so that sites can tailor assessments to specific needs and operations. It provides options for smaller sites that do not have on-site internal assessment capabilities or do not think a full PSSAP General Assessment is warranted. It is intended that assessments focus on higher risk activities and includes an evaluation of both the quality of written programs at a site and the effectiveness of field implementation of those programs.

Tank Modeling and Its Condition Assessment using Terrestrial Laser Scanner

Condition assessment of the tank must be carried out since it is related to Health, Safety, and Environment (HSE). Assessment is carried out by referring to the applicable standards. This study aims to create a 3D (Dimension) model and assess the tank using Terrestrial Laser Scanner technology. This includes planning, data acquisition, data processing, and data visualization. The data processing process starts with the registration stage with the cloud-to-cloud method, georeferencing, 3D modeling using point cloud, and tank assessment filtered point cloud data. Assessment includes analysis of volume, verticality/slope (in terms of the difference between upper and lower tank), and roundness calculations. The 3D model of the tank was generated with a registration error of less than 1 cm. The volume of tank I and tank II were calculated to 134.108 m3 and 134.067 m3, respectively. The difference between the upper and lower radius for each tank ranges from 2 to 10 mm. Considering the results and recalling the API 650 standard (American Petroleum Institute), each tank is considered reliable and in a good condition.

Evaluation of the Static Design Procedure in the Canadian Foundation Engineering Manual for Piles in Cohesionless Soil

Piles provide a convenient solution for heavy structures, where the foundation soil bearing capacity, or the tolerable settlement may be exceeded due to the applied loads. In cohesionless soils, the two frequently used pile installation methods are driving and drilling (or boring). This paper reviews the results of a large database of pile load tests of driven and drilled piles in cohesionless soils at various locations worldwide. The load test results are compared with the static analysis design method for single piles recommended in the Canadian Foundation Engineering Manual (CFEM) and other codes and standards such as the American Association of State Highway and Transportation Officials, Federal Highway Administration, American Petroleum Institute, Eurocode, and the Naval Facilities Engineering Command. An improved pile design procedure is proposed linking the pile design coefficients and to the friction angle of the soil, rather than employing the generalized soil type grouping scheme previously used in the CFEM. This improvement included in the new version of the CFEM 2021 produces a more unified value of the pile capacity calculated by different designers, reducing the obtained design capacity discrepancies.

A Numerical Investigation to Determine the p–y Curves of Laterally Loaded Piles

This paper focuses on a numerical approach to finding the p–y curves for laterally loaded piles. The Drucker–Prager plastic model is employed and implemented within a finite element MATLAB code. The pre- and post-processing code for Gmsh and related numerical tools are established as well. The p–y curve results from this new approach have been validated and compared to the typical design equations of API (American Petroleum Institute) and Matlock. The validation reveals that the code leads to lower p–y curves than the API and Matlock equations when the horizontal displacement is less than 0.35 times the diameter of the pile (B). A sensitivity analysis of the number of elements and the interface thickness is presented. The results indicate that the obtained p–y curves are independent of the two factors. Finally, the influence of clay content on the p–y behavior is investigated by the implemented MATLAB code. When y < 0.15B, the same lateral capacity values are resulted at clay contents of 27.5% and 55%, and they are higher than the ones for 0% clay content. The p–y curves show a decreasing trend with increasing clay content after y > 0.15B.

OCTG Connection Testing Aiding in the Integrity of Multi-Fractured Horizontal Wells

With the increase in shale oil and gas activity and complexity, companies deploy new solutions to safely and efficiently drill, complete, and produce wells in unconventional plays. These include Oil Country Tubular Goods (OCTG) connections, which must withstand installation, stimulation, and production loads specific to this application. Industry available standards provide manufacturers and operators a framework for quality founded on best practices and testing. In some instances, existing testing protocols may not be adequate (e.g. insufficient or overconservative) to assess connections’ performance for this application. For this reason, the American Petroleum Institute established an expert working group to develop Technical Report 5SF (TR 5SF) intended to evaluate casing connections performance in multi-fractured horizontal wells. The objective of this paper is to present a set of verified testing protocols applicable to casing connections used in the most common shale plays, complementing the existing body of knowledge. We discuss testing elements and parameters tailored to the conditions of various shale plays. Based on the operations planned for the life of a well, the testing procedure is adjusted to resemble the expected conditions and loads in the correct order. This includes make-up, high-cycle fatigue associated with the casing string installation, thread compound degradation under temperature and time, and mechanical load cycles generated by stimulation. Specimen sealability is confirmed under production loads, after which failure testing is performed. Some of the inputs to build the testing protocol are: maximum internal pressure, axial load, dogleg severity, number of cycles, temperature, and fluid type. Since connections play a crucial role in the integrity of a well, a testing procedure to ensure their performance is shown. Testing protocols for Multi-fractured Horizontal Wells (MFHW) applied to two connection types are presented, highlighting how tailored testing protocols and robust engineering improve product reliability and well integrity assurance. We compile a set of testing inputs for the most relevant shale plays worldwide, together with the testing elements, sequence, and acceptance criteria. This should help end users validate and benchmark products’ performance while improving industry knowledge of connections capabilities.

Failure Mode Determination of API 12F Shop-Welded Tanks with a New Roof-to-Shell Junction Detail

The API 12F is the specification for vertical, aboveground shop-welded storage tanks published by the American Petroleum Institute (API). The nominal capacity for the twelve tank designs given in the current 13th edition of API 12F ranges from 90 bbl. (14.3 m3) to 1000 bbl. (159 m3). The minimum required component thickness and design pressure levels are also provided in the latest edition. This study is a part of a series research project sponsored by API that dedicates to ensure the safe operation of API 12 series storage tanks. In this study, the twelve API 12F tank designs presented in the latest edition are studied. The elastic stress analysis was conducted following the procedures presented in the ASME Boiler and Pressure Vessel Code 2019, Section VIII, Division 2 (ASME VIII-2). The stress levels at the top, bottom, and cleanout junctions subject to the design pressures are determined through finite element analysis (FEA). The bottom uplift subjected to design pressures are obtained, and the yielding pressure at the roof-shell and shell-bottom junctions are also determined. The specific gravity of the stored liquid is raised from 1.0 to 1.2 in this study. A new roof-shell attachment detail is proposed, and a 0.01 in. (0.254 mm) gap between the bottom shell course and the bottom plate is modeled to simulate the actual construction details. In addition, the flat-top rectangular cleanout presented in the current edition of API 12F is modeled.

Perbandingan Kurva S-N dalam Menentukan Umur Kelelahan Struktur

Struktur anjungan lepas pantai merupakan infrastruktur yang menyokong proses pengeboran minyak di lepas pantai. Sebagian besar struktur anjungan lepas pantai di Indonesia berdiri sejak tahun 1971. Faktor utama masih beroperasi anjungan lepas pantai adalah terkait dengan kebutuhan masyarakat akan minyak bumi. Oleh karena itu, perlu menjadi perhatian khusus agar struktur anjungan lepas pantai dapat beroperasi dengan aman. Analisis kelelahan (fatigue) struktur akan memberika estimasi umur kelelahan struktur, yang mana dapat dijadikan acuan dalam melakukan pencegahan terhadap kegagalan struktur. American Petroleum Institute (API) mengeluarkan dua jenis kurva S-N dalam penentuan umur kelelahan struktur yaitu API X-X’ dan WJT (Welded Joint). Kurva S-N WJT merupakan kruva S-N baru yang dikeluarkan oleh API pada tahun 2014. Dengan adanya kurva S-N terbaru, untuk struktur anjungan lepas pantai tua (sejak tahun 1973) yang masih beroperasi sampai saat ini diperlukan penyesuaian dalam menentukan umur kelelahan. Penelitian ini akan membandingkan analisis kelelahan menggunakan kedua grafik tersebut. Berdasarkan hasil penelitian diperoleh kurva S-N WJ menghasilkan umur kelelahan yang lebih kecil dibandingkan dengan kurva S-N API X. Secara persentase rentang perbedaan hasilnya adalah 11%-79%, hal ini bergantung pada lokasi dan elevasi komponen struktur.