
 Appropriate selection of a bottomhole assembly (BHA) is critical to the success of a drilling operation. In US land drilling, these assemblies are often selected using local heuristics rather than rigorous analysis. These heuristics are frequently derived from the incentives of the directional contractor as opposed to incentives for the operator. Large motor bends enable more rotation through the curve and reduce the possibility of tripping for build rates. Unstabilized motors are believed to aid sliding and tool face control. Both of these practices lead to drilling a more tortuous wellbore and may cause problems later in the well’s life. This study quantifies the impact of these practices and proposes alternatives that can balance the needs of directional companies with the desire of operators for high-quality wellbores.
 More than 60 conventional motor assemblies used to drill curves in the Eagle Ford and Permian basins were analyzed for directional performance using commercial drillstring analysis software. The sliding and rotary tendencies were modeled through the curve across a range of potential drilling conditions. Expected build-rate models were validated by comparison to the maximum achieved doglegs in the directional surveys. When available, additional validation was performed using motor yields calculated from slide sheets. The validated models were compared to the dogleg severity (DLS) requirements for each assembly’s respective well plan. Comparisons of slide ratios and slide/rotate tendencies of the BHAs were used to estimate the impact on wellbore quality using the tortuosity metric proposed by Jamieson (2019).
 Typical well plans for both basins had curves of 10° per 100 ft with no well plan greater than 12° per 100 ft. Typical BHAs were capable of >15° per 100 ft under normal sliding conditions, with some assemblies capable of >20° per 100 ft of build. Predicted build rates were validated by slide sheets and observed DLSs. Common characteristics among assemblies with excess capacity were high-bend angles (≥2°) and minimal stabilization. These understabilized assemblies exhibited unstable rotary tendencies across a range of drilling parameters. The combination of high-build rates with rotary drop masks the true level of tortuosity in a wellbore, leading to an underestimation of unwanted curvature. A minority of the assemblies used a lower motor bend angle (<2°) combined with multiple stabilizers. These assemblies had a more consistent directional capability throughout the curve and exhibited stable behavior in rotation. The success of these assemblies confirms that there is potential for tailoring BHA designs to improve wellbore quality without compromising the technical objectives of the well.
 As increasing attention is afforded to the topic of wellbore quality, it is important to have methods available to technically achieve high-quality wellbores. In addition to the management of drilling practices, it is also important to have an appropriate BHA design that can enable those practices.

When Slick Is Not Smooth: Bottomhole Assembly Selection and Its Impact on Wellbore Quality

Abstract With increasing numbers of unconventional horizontal wells on single pads and the desire to get deeper unconventional wells drilled to TD as economically as possible, higher well deviations and Dogleg Severities (DLSs) have posed challenges for Electrical Submersible Pump (ESP) conveyance. These challenges have led to situations where high bending stress during ESP conveyance has led to early ESP failure. To mitigate the potential for high bending stress during ESP conveyance, there has been: A renewed focus on drilling intermediate hole sections with low DLS, andWorkflow changes to obtain and analyze gyro surveys on wells following handover from Drilling before perf &amp; frac operations. Summarized in the paper is a series of short run ESP failures in the Permian Basin that led to these new workflows for A/L selection and ESP conveyance planning. The study was initiated with a review of ESP teardown reports which revealed that most failures in the study area were not linked to high ESP bending stress during conveyance, but rather to Iron Sulfide (FeS) scaling within the ESPs. Nonetheless, Software was used to analyze and quantify ESP bending stress during conveyance for historical and future wells,A FeS scale inhibitor trial was initiated by adding chemical to the frac stages for some future ESP candidate wells, andApproximately 30 high resolution (1-ft) gyro surveys were collected in 5 ½" and 7" casing and processed at 1’, 15’, 25’ and 100’ intervals. Various metrics were calculated using the data, including wellbore DLS and Effective Rigid Pass-Through Diameter to highlight the advantage of gyros over traditional low resolution MWD surveys in wells where ESPs are planned. 

ESP Conveyance Modelling in Higher DLS Wells

Periode Juli 2020-Januari 2021 sumur sucker rod pump di Struktur Tanjung mengalami 54 kali perawatan terdiri dari 72 % tubing leak dan parted rod, 15 % low pump effisiensi dan 13 % pump stuck. Periode tersebut TJG-140 mengalami 2 kali perawatan akibat tubing leak pada November 2020, lifetime 135 hari dan Januari 2021, lifetime 45 hari. Walaupun perubahan design sudah dilakukan November 2020, namun belum efektif dalam meningkatkan lifetime sumur dikarenakan pemasangan rod guide belum optimal. Design rod guide perlu mempertimbangkan neutral point dan buckling point dengan menentukan koefisien buckling (wear point) hasil plot data neutral point vs kedalaman tubing bocor. Penentuan kedalaman buckling point dapat membantu memprediksi kedalaman tubing leak dan parted rod. Pada design berikutnya, kedalaman neutral point 667 ft diatas pompa atau 2876,06 ft, kedalaman wear point 3285,6 ft dan rod guide sebanyak 26 ea. Pemasangan dilakukan Januari 2021 dan monitoring sampai akhir 2021. Selama monitoring, terjadi 2 kali perawatan tanggal 25 Juli 2021 akibat scale menutupi pump intake dengan lifetime 197 hari dan 21 November 2021 akibat pump stuck dengan lifetime 119 hari. Selama 2021 tidak mengalami perawatan sumur akibat tubing bocor atau rod parted sehingga meningkatkan lifetime sumur dari 45 hari menjadi 197 hari.

Optimasi Design Rod Guide Untuk Meningkatkan Performance Sumur Sucker Rod Pump Di Pertamina EP Field Tanjung

The oil and gas industry generates substantial amounts of polymeric waste each year, including sucker rod guides manufactured from premium thermoplastics such as Polyphenylene Sulphide (PPS), Polyacrylamide (PAA), Polyamide (PA), and Polyether ether ketone (PEEK). It is estimated that, annually, approximately 18,600 metric tonnes of polymeric sucker rod guides are discarded worldwide, contributing significantly to landfill accumulation. This paper critically reviews the behaviour of polymeric rod guides when exposed to downhole environments where high temperature, pressure, contamination, and severe mechanical stresses act simultaneously. These components are essential in maintaining system reliability, yet research and development on polymeric rod guides remain limited, and investigations into their degradation and failure mechanisms are non-existent. In addition, there are currently no established approaches for recycling or reusing worn polymeric guides, which restricts progress toward sustainability and contributes to the increased accumulation of polymer waste in landfills. This review highlights these gaps and discusses future research directions that could improve the performance and service life of glass-fibre-reinforced polymeric components, while also creating opportunities for recycling and circular economy. 

Composite Polymeric Sucker Rod Guides: State-of-Practice, Causes of Failure, and Circular Economy Opportunities


 In rod-pumped systems, the locations to install rod guides along the rod are determined through the analysis of calculated side forces exerted on/by the rod string. The side forces are computed from axial forces in combination with information about the trajectory of the rod string in the well. Traditionally, the trajectory of the rod string is estimated from directional survey data, obtained by magnetic or gyroscopic surveys at typically 100ft reporting intervals. However, because the surveys are run in open hole, in casing, or in tubing, it is the trajectory of these structures that are described by the directional data. None of them are accurate representations of the actual trajectory of the rod string, implying that the resulting side forces may suffer from reduced accuracy, and therefore are not optimal for decisions on rod guide placement. Additionally, due to the low resolution survey data, local variations in the wellbore trajectory within the survey intervals, which may affect the forces on the rods, may be undetected.
 In a previous paper we developed a method for analyzing the small-scale tortuosity of a wellbore from high-resolution (1ft) survey data. One important outcome of this analysis is the finding that high small-scale tortuosity substantially narrows the free passage through a wellbore or tubing. The narrowing is quantified in terms of the reduction in the effective diameter of a device that can be placed in the wellbore. In this paper, the technique has been extended for the calculation of points along the wellbore where the rod string is expected to make contact with the tubing. This is an important result by itself, indicating where rod guides may be needed along the rod string. With these points of contact, the trajectory, or shape of the rod within the production tubing is estimated. The use of this estimate instead of the traditional directional survey data in the calculations of side forces is expected to improve the accuracy of the results.
 The technique has been applied to a number of field cases, and two are presented in this paper. The results show that the forces on the rod calculated from the proposed technique are similar to, and exhibit the same general trend as the forces calculated with conventional methods. However, there are some differences, due primarily to the use of the estimated shape of the rod string in the proposed method. The forces on the rod at the estimated points of contact of the rod and the tubing can be extracted and used for rod guide placement decisions.
 By providing improved estimates of contact point locations and the forces acting between the rod and the tubing, the method may help to optimize the rod pumping system for producing wells. It may help to explain occurrences of pump failures, erosion of the production tubing by the rods, and other issues that are not fully understood. This may result in reduced failure rates, energy savings, and cost savings resulting from reduced workovers and production losses.

Rod-Guide Placement Based on High-Resolution Tortuosity Analysis of Production Tubing

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Rod-Guide Placement Based on High-Resolution Tortuosity Analysis of Production Tubing