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Towards Automated Condition Monitoring of Blowout Preventer Wellbore Packers Towards Automated Condition Monitoring of Blowout Preventer Wellbore Packers Se Un Park1, Rajesh Kumar Bade2, Daniel Barker3, and Daniel Edgardo Viassolo4 1,4Schlumberger, 1430 Enclave Pkwy., Houston, TX, 77077, USA [email protected], [email protected] 2,3Schlumberger, 4601 Westway Park Blvd., Houston, TX 77041, USA [email protected], [email protected] ABSTRACT of mud serves as primary means of controlling wellbore pressure during drilling, a BOP forms the final layer of According to Bureau of Safety and Environmental protection that prevents a loss of well-control (LOWC) event Enforcement (BSEE), in 2017 a total of 45 out of 59 rigs from becoming a hazardous blowout. A study by Per Holland operating in the Gulf of Mexico reported component failures and the Bureau of Safety and Environmental Enforcement of well control related equipment. The aftermath of the oil (2016) reports that approximately 60% of LOWC events spill from the Deepwater Horizon rig provides stark occur during drilling operations. illustration that acceptance of the equipment failure status quo is untenable. In this work, the authors propose novel A BOP is placed on top of wellhead with drilling equipment automated strategies to monitor the health of blowout going through it into a well. Depending on operating context preventers (BOPs) on offshore drilling rigs. Using physics- of LOWC event, a BOP must either isolate wellbore pressure based models, we demonstrate computational detection of by sealing around a tubular or drill pipe (Figure 1) or shear a pressure tests by identifying characteristic features in time- tubular before isolating wellbore pressure. The task of series pressure data. After detection, we present a isolating wellbore pressure from the drilling rig is methodology for extracting features relevant for prognostic accomplished by hydraulically energized elastomeric health monitoring, including pressure decay and hold components referred to as ‘packers’ or ‘seals’ (Figure 2). For durations. Augmenting these computational models with operational flexibility and redundancy, multiple BOPs are domain knowledge from BOP experts, we produce health integrated vertically to form a ‘BOP stack’ (Figure 3). indices (HIs) for the respective equipment as the output. In A reliability study by American Bureau of Shipping and the addition, we demonstrate the optimized enumeration and Bureau of Safety and Environmental Enforcement (2013) identification of possible pressure test plans for BOPs in indicates that approximately 50% of BOP stack failures are different combinatorial configurations. By combining our attributable to BOPs, while remaining are due to the BOP novel detection approach with health indices and automated control system and other ancillary equipment. Due to its test planning, this work contributes to prediction and safety service, BOP failures do not become obvious until an amelioration of well control equipment failures on offshore operational demand is placed upon it. drilling rigs. Periodic tests of BOP stack allow drilling contractors to maintain and control the integrity of its functional service, as 1. INTRODUCTION suggested by Martins, Cardoso, Tammela, Colombo, and Matos (2018). One type of such tests is a pressure test. A A blowout preventer (BOP) is a safety-critical drilling rig pressure test simulates a ‘kick’ (undesired increase in component used primarily during exploration, development wellbore/annulus pressure) to assess ability of BOP packers and workover phases of an oil and gas field. While a column to isolate anticipated well pressure. Because high pressure Se Un Park et al. This is an open-access article distributed under the terms flowing fluid used in the test can erode metallic components of the Creative Commons Attribution 3.0 United States License, which and wear-out elastomeric components such as rubber side permits unrestricted use, distribution, and reproduction in any medium, packers in rams in a BOP stack, typical aging effects of provided the original author and source are credited. performance degradation over time are expected in 1 ANNUAL CONFERENCE OF THE PROGNOSTICS AND HEALTH MANAGEMENT SOCIETY 2018 mechanical properties of the system. The aging effects In this work, to detect any sign of failures upon pressure manifest in form of leaks of wellbore fluid past well-bore holding capacity in a component of a BOP stack, an packers. The integrity of these components must be assessed automated solution within a prognostic health monitoring regularly by simulating pressures on them. For a pressure test, (PHM) framework is proposed, in accordance with the testing engineers temporarily stop regular rig functions Vachtsevanos, Lewis, Roemer, Hess, and Wu (2006), by and close a combination of annular preventers, rams, and using the above-mentioned pressure test data. A method that valves to apply pressure within a BOP system and measure can identify and characterize pressure tests by searching the the pressure changes to assure that the BOP can hold the starting and finishing points of the test considering realistic specified pressure. Towards this, BOP stack is instrumented physical constraints, is developed. Primary data consists of with pressure and temperature (P/T) transducers exposed to statuses of subsea BOP stack components and pressure as wellbore. measured by a P/T sensor exposed to annulus of a BOP stack. Figure 1. Blowout Preventers (BOP) that seal around drill pipe: Pipe Ram Preventer (above) and Annular Preventer. (below) Figure 3. BOP Stack with 19x components: 1x Annular, 2x Shear Ram, 3x Pipe ram, 11x Gate valves and 2x Line isolation valves. Pressure & Temperature Transducer mounted under Lower Pipe Ram (LPR) and under Choke Isolation valve (CIV). The method also identifies which components of a BOP stack are being tested, because it comprises of numerous components such as annular BOPs, ram BOPs and fail-safe valves. This enables classification of test configuration and benchmarking of test performance for condition monitoring. Furthermore, a set of complete pressure tests must cover Figure 2. Wellbore Packers isolate pressure from the well in testing of all components by considering combinations of the event of a ‘kick’. Packers during normal operation (above) closed, pressure-holding components. This needs to be and Packers during test or ‘kick’(below). planned to efficiently perform pressure tests of all 2 ANNUAL CONFERENCE OF THE PROGNOSTICS AND HEALTH MANAGEMENT SOCIETY 2018 components and avoid redundant tests. As testing often precludes further operational activities, test plan optimization is desirable to drilling contractors and operators to minimize non-productive time (NPT) on the rig. With the goal of automating identification of tested components as well as for test planning, a simulator based on the specific structure of a BOP stack and physical constraints of each component is proposed. As a practical example, a pressured line may have multiple valves, e.g., inner/outer and upper/lower valves, and two sides of each valve should be tested to determine the health states of subcomponents; e.g., the right side of the subcomponent in upper inner choke valve. Also, pressured annular preventers and ram preventers typically have one directional resistance in pressure by Figure 4. An example of raw BOP stack pressure test data. design, i.e., pressure coming from the wellbore. Under the (x-axis: time, y-axis: wellbore test pressure in bars) known states of BOP stack components, the simulator can determine lines and cavities that are pressurized, components Another issue of the pressure data may include resolution of tested, pressurized sides of tested components, and pressure and sampling intervals or the combination of the components whose status is irrelevant. The simulator two. This is especially noted during pressure tests where the discussed herein can be used in automation of test-planning. differential pressures are small leading to sparse data sets. Irregularly sampled times series data is difficult to analyze or 2. METHODS apply standard signal processing algorithms. The data is thus resampled or interpolated for further processing if needed. 2.1. Detection of Pressure Tests 2.1.2. Identification of Characteristic Points of Pressure 2.1.1. Pressure Data Processing Tests For the given BOP structure considered in this work, there The characteristic points of pressure tests include starting and are two P/T (pressure and temperature) sensors: pressure ending points of pressure test hold-period. The test pressure sensor below the lower pipe ram (LPR) and above the pattern is mostly rectangular. This pattern has a seemingly wellhead connector, is referred to as LPR Pressure. The other flat top, but in fact has a small negative slope during the tests. sensor is located on the choke line. LPR Pressure data has The transitions of test-pressure (increase or decrease) are better exposure to the pressure of the primary rams in the sudden and manifested as near-vertical lines in the time scale BOP stack because of the proximity and direct connectivity of hours as seen in Figure 4 and 5. to the wellbore (For example, see Figure 3). While Maximum Limiting the prototypical pattern to a rectangular one, the first allowable working (rated) pressure of the BOP stack is 690 order differentials, as instantaneous or point-wise slopes, are bar, the range of pressure sensors used is 0-1400 bar. ostensibly sufficient to identify the characteristic points. The pressure data from the LPR sensor
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