Assessment of Lost Circulation Material Particle-Size Distribution on Fracture Sealing: A Numerical Study

Summary Lost circulation materials (LCMs) are essential to combat fluid loss while drilling and may put the whole operation at risk if a proper LCM design is not used. The focus of this research is understanding the function of LCMs in sealing fractures to reduce fluid loss. One important consideration in the success of fracture sealing is the particle-size distribution (PSD) of LCMs. Various studies have suggested different guidelines for obtaining the best size distribution of LCMs for effective fracture sealing based on limited laboratory experiments or field observations. Hence, there is a need for sophisticated numerical methods to improve the LCM design by providing some predictive capabilities. In this study, computational fluid dynamics (CFD) and discrete element methods (DEM) numerical simulations are coupled to investigate the influence of PSD of granular LCMs on fracture sealing. Dimensionless variables were introduced to compare cases with different PSDs. We validated the CFD-DEM model in reproducing specific laboratory observations of fracture-sealing experiments within the model boundary parameters. Our simulations suggested that a bimodally distributed blend would be the most effective design in comparison to other PSDs tested here.

Investigation of the Internal Blowout Accident Involving Overpressured Reservoirs: Case of CI-11 Well, Southern Tunisia

Summary This study consists of an assessment of the ecological accident implicating the Continental Intercalaire-11 (CI-11) water well located in Jemna oasis, southern Tunisia. The CI-11 ecological accident manifested in 2014 with a local increase of the complex terminal (CT) shallow water table salinity and temperature. Then, this phenomenon started to spread over the region of Jemna, progressively implicating farther wells. The first investigation task consisted of logging the CI-11 well. The results revealed an impairment of the casing and cement of a huge part of the 9⅝ in. production casing. Historical production records show that the problems seem to have started in 1996 when a sudden production loss rate occurred. These deficiencies led to the CI mass-water flowing behind the casing from the CI to the CT aquifers. This ecological accident is technically called internal blowout, where water flows from the overpressurized CI groundwater to the shallower CT groundwater. Indeed, the upward CI hot-water flow dissolved salts from the encountered evaporite-rich formations of the Lower Senonian series, which complicated the ecological consequences of the accident. From the first signs of serious water degradation in 2014 through the end of 2018, several attempts have been made to regain control of annular upward water flow. However, the final CT groundwater parameters indicate that the problem is not properly fixed and communication between the two involved aquifers still persists. This accident is similar to the OKN-32 case that occurred in the Berkaoui oil field, southern Algeria, in 1986, and included the same CI and CT aquifers. Furthermore, many witnesses claim that other accidental communications are probably occurring in numerous deep-drilled wells in this region. Concludingly, Jemna CI-11, Berkaoui OKN-32, and probably many other similar accident cases could be developing regional ecological disasters by massive water resource losses. The actual situation is far from being under control and the water contamination risk remains very high. In both accidents, the cement bond failure and the choice of the casing point are the main causes of the internal blowout. Therefore, we recommend (1) a regional investigation and risk assessment plan that might offer better tools to predict and detect earlier wellbore isolation issues and (2) special attention to the cement bond settlement, evaluation, and preventative logging for existing wells to ensure effective sealing between the two vulnerable water table resources. Besides, in the CI-11 well accident, the recovery program was not efficient and there was no clear action plan. This increased the risk of action failure or time waste to regain control of the well. Consequently, we suggest preparing a clear and efficient action plan for such accidents to reduce the ecological consequences. This requires further technical detailed study of drilling operations and establishment of a suitable equipment/action plan to handle blowout and annular production accidents.

Single Trip Deployment of Multistage Completion Liners Through the Use of Interventionless Flotation Collars

Summary In difficult wellbores, the traditional method for deploying liners was to run drillpipe. The case studies discussed in this paper detail an alternative method to deploy liners in a single trip on the tieback string so the operator can reduce the overall costs of deployment. Previously, this was not often practical because the tieback string weight could not overcome the wellbore friction in horizontal applications. In each case, a flotation collar is required to ensure there is enough hookload for the deployment of the liner system. The flotation collars used are an interventionless design using a tempered glass barrier that shatters at a predetermined applied pressure. The glass debris is between 5 and 10 mm in diameter and can be easily circulated through the well without damaging downhole components. This is done commonly on a cemented liner and cemented monobore installations, but more rarely with openhole multistage completions. The authors of this paper have overseen thousands of cemented applications of this technology in Western Canada, the US onshore, Latin America, and the Middle East. For openhole multistage completions, the initial installation typically requires a ball drop activation tool at the bottom of the well to set the hydraulically activated equipment above. The effects of circulating the glass debris through one specific style of activation tool were investigated. Activation tools typically have a limited flow area and could prematurely close if the glass debris accumulates. Premature closing of the tool would leave drilling fluids in contact with the reservoir, potentially harming production. The testing was successfully completed, and the activation tool showed no signs of loading. This resulted in a full-scale trial in the field, where a 52-stage, openhole multistage fracturing liner was deployed using this technology. Through close collaboration with the operator, an acceptable procedure was established to safely circulate the glass debris and further limit the risk of prematurely closing the activation tool. This paper discusses the openhole and cemented multistage fracturing completion deployment challenges, laboratory testing, and field qualification trials for the single trip deployed system. It also highlights operational procedures and best practices when deploying the system in this fashion.

Novel Active Inflow Control Technology for Optimized Flow and Reduced Intervention

Summary Integrating a flow control sliding sleeve into a sand screen can provide multiple advantages to the user in controlling the production inflow, but it comes with an increased completion cost as well as an increase in the number of interventions required when it is time to operate those valves. Especially in long horizontal wells, this can become time-consuming and inefficient. A few technologies exist to address this issue, but they either are too complex or require specialized rigging equipment at the wellsite, which is not desirable. As described herein, a unique, fit-for-application modular sliding sleeve sand screen assembly with dissolvable plugs was developed that eliminates the need for washpipe during run-in-hole (RIH) and allows flow control from several screens by means of a single sliding sleeve door (SSD), thereby also optimizing the subsequent intervention operations by reducing the number of SSDs in the well. The design and field installation of these modular screens is presented in this paper. The new modular sand screen consisted of an upper joint, modular middle joint, modular middle joint with an inflow control device (ICD) integrated into an SSD (with optional dissolvable plugs), a lower joint, and novel field-installable flow couplings between them. The design allows for any number of non-ICD/SSD screen joints to be connected to any number of ICD/SSD joints in any order. A computer-aided design was followed to achieve all the operational and mechanical requirements. Computational fluid dynamics (CFD) was used to optimize the flow performance characteristics. Prototypes were manufactured and tested before conducting successful field trials. The design process, development, and field installation results are presented herein.

Thermodynamic Basis of Brine Density on Pressure, Temperature, and Chemical Composition in Ultrahigh Pressure/High Temperature Environments

Summary Temperature change and the pressure/volume/temperature (PVT) response of wellbore annular fluids are the primary variables that control annular pressure buildup in offshore wells. Though the physics of annular pressure buildup is well understood, there is some ambiguity in the PVT models of brines. While custom tests can be performed to determine the PVT response of brines, they are time-consuming and expensive. In this light, our paper presents a method to determine the density of brines from their chemical composition, as a function of pressure and temperature. It compares theoretical predictions with the results of tests on brines used in our industry and available test data from the oil and gas and other industries. In 1987, Kemp and Thomas used the principles of chemical thermodynamics to develop equations for the density of brines as a function of pressure and temperature and their electrolytic actions. However, their paper contained two (inadvertent, and probably typographical) errors. One of the errors lay in the set of the Debye-Hückel parameters, and the other was contained in the coefficients of the series expansion for the infinite dilution molal volume. Furthermore, they (inadvertently) did not mention the role of a crucial parameter that accounts for the interaction between the ionic constituents of the salt. As a result, nearly a generation of engineers in our industry has been unable to reproduce their valuable results or apply their technically rigorous results to other brine chemistries. In this paper, we return to the basic equations of chemical thermodynamics and the principles of stoichiometry and delineate the inadvertent errors that had crept into the Kemp and Thomas equations. We then present the rectified equations and reproduce their example with the corrected results. Further, we compare the predictions from the original Kemp and Thomas work with results from a leading chemical engineering model. Finally, we compare the results of theoretical models with test measurements from the laboratory and characterize the uncertainty inherent in each model. Thereby, we have rendered the Kemp and Thomas (1987) model useful to the well design community.

An Experimental Study of the Wear Characteristics of Tubulars Made from Corrosion-Resistant Alloys

Summary Casing wear is the process of progressive loss of wall thickness owing to relative motion between the drillstring and casing. The amount of casing wear depends on conditions, such as the downhole forces, the accumulated time of contact between drillstring and casing, and the materials used. This process is complex and involves abrasive, adhesive, and corrosive wear mechanisms that are difficult to predict. To deal with the complexity of the conditions, a simple but effective wear model is used in the industry to estimate tubular wear in drilling and intervention operations. The model is based on abrasive and adhesive wear, and the effects of corrosion are not considered. In addition, an empirical part of the model known as the correction factor is based exclusively on experimental carbon-steel test data. Tubulars made of corrosion-resistant alloys (CRAs) are known to exhibit abnormal wear characteristics. A series of experiments has been designed and performed to investigate the wear characteristics of CRAs. These experiments resulted in excessive wear factors for the CRA casing samples, demonstrating their susceptibility to wear. This study finds that omitting the correction factor from the calculation procedure can greatly improve wear estimates for some CRAs. Removing the correction factor results in a linear wear-work relationship that reflects the actual wear trends from test results. However, further studies are needed to confirm correction factors and more accurate wear calculation procedures for CRA tubulars in general.

How to Improve Accuracy of a Kick Tolerance Model by Considering the Effects of Kick Classification, Frictional Losses, Pore Pressure Profile, and Influx Temperature

Summary Kick tolerance (KT) calculation is essential for a cost-effective well design and safe drilling operations. While most exploration and production operators have a similar definition of KT, the calculation is not consistent because of different assumptions that are made and the computational power of KT calculators. Dynamic multiphase drilling simulators usually provide KT estimates with a minimum number of assumptions. They are much more accessible nowadays for use in predicting the behavior of multiphase flow in drilling and well control operations. However, as far as we observed, the simulation services are mainly used for complex and marginal wells in which low KT may impose additional casing strings, unconventional costly drilling practices, or a high risk of major well control events. Thus, companies often use simplified steady-state models for relatively uncomplicated wells through their own KT calculation worksheets. This practice is usually justified by the misconception that simplified models are always conservative and give less KT than actual conditions. In contrast, some simplifications may lead to higher operational risks due to an overestimated KT, depending on well conditions and parameters. The primary objective of this work was to perform a quality assurance/quality control on KT calculation practices in Company P. Later on, based on our findings, we determined some solutions to improve accuracy in the simplified KT worksheets commonly used by engineers across the company. This became a driver for generating a new KT worksheet (Company Model), in particular for situations in which engineers do not have access to a kick simulator. However, it should not mislead readers about the requirements of the simulator for complex and low-KTwells. Quality assurance/quality control and subsequent investigations found that there are some important criteria and parameters that affect KT calculations, but they are missing in many simplified models or ignored by engineers because they are unaware of or lack adequate references. After reviewing relevant academic literature, common practices and assessing several off-the-shelf software programs, we generated a computer program using Visual Basic for applications to address KT sensitivity to different parameters in steady-state conditions. The newly developed program is based on a single gas bubble model that applies the effect of annular frictional losses, influx temperature, gas compressibility factor, well trajectory, and bottomhole assembly (BHA). Moreover, the program differentiates between swabbing and underbalanced conditions. A logical test is applied to determine the type of kick before computing the relevant influx volume. This kick classification concept is ignored in many KT models; this is a common mistake that leads to misleading results. The annular pressure loss (APL) parameter is sometimes assumed to be zero in KT spreadsheets, while as an additional stress load on the wellbore, it affects the kick budget and must be considered.

Evaluating Precision of Annular Pressure Buildup (APB) Estimation Using Machine-Learning Tools

Summary Annular pressure buildup (APB) is caused by heating of the trapped drilling fluids (during production), which may lead to burst/collapse of the casing or axial ballooning, especially in subsea high-pressure/high-temperature wells. The objective of this paper is to apply machine-learning (ML) tools to increase precision of the APB estimation, and thereby improve the fluid and casing design for APB mitigation in a given well. The APB estimation methods in literature involve theoretical and computational tools that accommodate two separate effects: volumetric expansion [pressure/volume/temperature (PVT) response] of the annulus drilling fluids and circumferential expansion (and corresponding mechanical equilibrium) of the well casings. In the present work, ML algorithms were used to accurately model “fluid density = f(T, P)” based on the experimental PVT data of a given fluid at a range of (T, P) conditions. Sensitivity analysis was performed to demonstrate improvement in precision of APB estimation (for different subsea well scenarios using different fluids) using the ML-basedmodels. This study demonstrates that, in several subsea scenarios, a relatively small error in the experimental fluid PVT data can lead to significant variation in APB estimation. The ML-based models for “density = f(T, P)” for the fluids ensure that the cumulative error during the modeling process is minimized. The use of certain ML-based density models was shown to improve the precision of APB estimation by several hundred psi. This advantage of the ML-based density models could be used to improve the safety factors for APB mitigation, and accordingly, the work may be used to better handle the APB issue in the subsea high-pressure/high-temperature wells.

Reduction in Backup Tool Requirements: Risks vs. Benefits, a Probability Analysis

Summary A review of the use of measurement while drilling (MWD), logging while drilling (LWD), and directional drilling (DD) tools mobilized to offshore drilling units in the North Sea highlighted an opportunity to lower operational cost for the operator and reduce capital used for the oilfield services company. An objective was set to develop a risk-based probability model that would assess the positive and negative financial impacts of reducing, or perhaps entirely removing, backup tools in this historically risk-averse basin. The scope of the initial analysis was a drilling campaign on a single rig contracted by the operator (Rig A). This analysis was then extended to review scenarios in which several operations in close proximity would share backup tools. The last 3 years of MWD/LWD/DD tool reliability data from North Sea operations, recorded by the oilfield services company, were used as an input. To assess the probability of failure, a binomial model was developed to create a binomial distribution for each tool to calculate the probability of having zero to X failures for a selected tool or bottomhole assembly (BHA) for a given number of runs. Three binomial models were developed to study the effect of “easy,” “moderate,” and “challenging” drilling environments on tool reliability. A financial risk model was designed to balance the probability-weighted cost of failure for the operator against the lower costs resulting from reduced tool provision by the oilfield services company. To better estimate risks and financial impacts on the project, a sensitivity analysis was performed on the financial risk model using the three binomial models. As a result of the analysis, it was demonstrated that recent improvements in tool reliability support a reduction in the provision of backup MWD/LWD/DD drilling tools for the majority of North Sea drilling scenarios.

Numerical Study on the Impact of Spiral Tortuous Hole on Cuttings Removal in Horizontal Wells

Summary Horizontal wells are designed to have smooth (straight), curved, and lateral sections. However, the actual drilled path usually suffers from unwanted undulations from the planned well trajectory known as wellbore tortuosity. Wellbore tortuosity can slow the drilling penetration rate, aggravate drillstring vibration and buckling, complicate the casing and cement job, and lead to inaccurate wellbore position. This paper presents a validated computational fluid dynamics (CFD) model to investigate the impact of wellbore tortuosity on hole cleaning. The Eulerian-Eulerian approach is used to simulate solid-liquid laminar flow in annular geometry using polyhedral mesh. Then, the impact of wellbore tortuosity on cuttings accumulation, annular pressure loss, and fluid velocity was investigated and compared with the flow behavior in a straight horizontal well. A parametric analysis of spiral period length, spiral amplitude, drillstring rotation, flow rate, annular eccentricity, drilling rate of penetration (ROP), and cuttings size was conducted to assess their influence on cuttings transport in spiral tortuous holes and their relative magnitude to other design or operating factors. Simulation results show that polyhedral mesh is an optimum meshing technique for spiral profile geometry. Wellbore tortuosity aggravates hole cleaning in lateral sections based on the length of the spiral period and/or the spiral amplitude. Reduction in cuttings velocity was observed in the top part of the spiral geometry (crest), causing large deposition of cuttings in this area compared to the spiral lower part (trough). Drillstring rotation from 0 to 200 rev/min is the critical range for efficient hole cleaning in spiral geometry. Cuttings size can improve cuttings accumulation if the particle size is larger than the viscous layer located near the bed velocity profile. The drilling ROP and annular eccentricity aggravate cuttings accumulation and bed deposition in a spiral hole, similar to what is normally observed in straight horizontal wells.