While optimizing hydrocarbon production, combining well intervention solutions can enable significant benefits due to reductions in risk exposure: fewer rig-ups and downs, less in-the-hole operating time and the carbon production and costs associated with rig time, especially when working from sub-sea intervention vessels. Operators in general, prefer to achieve multiple intervention objectives in a single descent in the well, if the operations complexity does not increase the risk exposure to an unacceptable level. Often, the risk of a mis-run, causing a second run, meets the cost vs value criteria for acceptable risk, when the large operating time savings of a successful combined run is considered. In collaboration with a mechanical e-line provider, North Sea operators developed three reliable combination solutions which increased their operational efficiency. Combining these most run services under more standard, common scope of work procedures, saved the operator time in planning, execution, risk exposure and money, while enabling them to produce hydrocarbons in the saved time. This paper will present the technology involved with these combined services, use a typical example of each and the cost savings achieved.

Lost circulation (LC) is extremely costly to many drilling operations due to loss of mud and productive time. Significant industry resources have been devoted to providing recommendations for both preventing and curing losses. These comprise bridging particles, settable pills and a focus on the better understanding, measurement and control of downhole pressures. The industry has also started to examine the relationship between downhole losses and fracture geometry. However, there has been very limited verification and utilization of such effort. Knowledge of the loss mechanism(s), location of the thief zone and fracture geometry is fundamental for understanding and treating losses effectively. The proposed method introduces a systematic approach for diagnosing lost circulation into potential root cause(s) by utilizing up to twenty-two diagnostic indicators. This allows the most appropriate treatments to be mapped to the suspected root cause. This technique supports the creation of preventative strategies during well planning. For example, if induced fractures are identified as the most likely root cause in the planning stage, then a wellbore strengthening formulation based on the fracture width estimation is recommended. A proper treatment can be designed based on the fracture width analysis as the data becomes invaluable in determining optimum sealing and effective treatment for losses into conductive natural fractures/faults. In case of loss events, the fracture width can be estimated based upon loss rate, the mud rheology, bottom hole pressure and pore pressure. Field experiences demonstrate that natural and induced fractures are the two most common root causes of losses. For induced fractures, fracture width usually develops beyond 3000-micron (µm) once losses have occurred and the preventive lost circulation materials (LCM) have not then worked effectively. If the bottom hole pressures can be kept below fracture propagation limits (or far-field minimum horizontal stress), then induced fractures will not cause significant volume of losses. The drilling induced fractures can be modelled by using in-situ stresses, well trajectory, bottom hole pressure, geothermal and mud temperature information.

Two of the most important parameters to monitor during a primary cementing job are the flow rate in and return flow rate measurements. To achieve optimum quality control of a primary cementing job, measuring annular return rates and comparing them with simulated data in real-time will provide better understanding of job signatures and result in the best possible top-of-cement estimation prior to running any cement evaluation log or taking decision to continue drilling the next section of the well. The return rate job signature along with the wellhead pressure is essential to understand the behavior and discrepancies between simulated and acquired surface data. Therefore, to assess the risk of job issues, such as unsuspected washout and lost circulation among others, accurate measurements of the return rate are critical. Historically, cement job evaluation has been limited by the fact that most drilling rigs do not have an accurate flow meter installed on the annulus return line, and a simple verification of mud tanks volumes versus pumped volume, as reported by drillers or mud loggers, more than often results in an unreliable assessment of the volume lost downhole, due to the unfamiliarity with the U-tubing effect and lack of data consolidation from the cement unit (flow rate in) and the rig (flow rate in & flow rate out). This paper will review a solution developed to mitigate the lack of a direct flow rate measurement by computing and displaying the return rate using either a paddle meter measurement or the derivative over time of the volume observed in the rig tanks.

Early detection and quantification of gas kicks during drilling and completions is essential to proper well control and in the prevention of blowouts. The utilization of distributed sensing techniques, acoustic (DAS) and temperature (DTS), enables real-time elucidation of these multiphase flow events. Identifying and validating event signatures (fingerprinting) in these sensing technologies is crucial to informing operators of how to interpret these data streams. Performing full-scale analysis allows these events to be properly characterized, given the complexities in the fluid mechanics and gas dynamics. This project utilizes a 9-5/8 inch and 5200 foot deep wellbore at the LSU PERTT Laboratory retrofit with distributed fiber optics (DAS and DTS) and 4 permanent pressure-temperature gauges to sense and visualize gas kick dynamics downhole in real time. Several experiments were performed involving the injection of nitrogen kicks through a chemical injection line and also by bullheading down 2-7/8 inch tubing in both stagnant and circulating water. Variations in flow rate, kick size, and backpressure are investigated including gas migration during shut-in. DTS and DAS data are collected downhole, along with gauge pressure and temperature at four depths along the wellbore. Data is consolidated with the rig recorded surface data to create a complete picture of the experiments. Several observations are possible with this new methodology. First, the gas kick is immediately visible (audible) entering the wellbore by the sensors and the gas front was traceable in real time as it rose to the surface, allowing for detection of a kick, improved estimation of kick size, and easy calculation of rise velocity. Second, the distribution of gas axially in the wellbore was visible and provided insights into the duration of the event. Third, the compressibility dynamics can be visualized with the DAS thus elucidating details of bubble and slugging sizes and dynamics and when discrete gas has completely circulated out of the wellbore. The frequency ban filtering of the data further augments the fidelity of gas bubble sizes and dynamics. These initial results provide a proof of concept for using downhole sensing for real time riser gas dynamic detection and characterization.

Development of unconventional reservoirs in North America has increased significantly over the past decade. The increased activity in this space has provided significant data with respect to through-tubing drillouts which had previously not been attainable. This paper is focused on using the field data from the Montney and Duvernay formations along with laboratory data and numerical modeling to understand the hole cleanout associated with through-tubing drillouts of frac plugs. Initially, an extensive full-scale flow loop laboratory testing program was conducted to obtain data on debris transportation for hole cleanout during through-tubing applications. The testing was conducted on various coiled tubing (CT)-production tubing configurations using various solid particles. The laboratory data was used to develop empirical correlations needed for a transient debris transport model. This model was then used for frac plug drillouts to ensure successful hole cleaning in actual field applications. Computational fluid dynamics (CFD) modelling was also used to further understand and quantify the differences between the laboratory data, field data and transient debris transport model results. The objective of the work conducted was to gain a better understanding of debris transport and validate the empirical modelling approach developed for hole cleaning. The validation process was conducted in several stages. The first stage was to validate the laboratory data against the Montney and Duvernay field data. The second stage was to verify the results obtained from the empirical model against the results obtained from a computational fluid dynamic model. The results from both modelling approaches were lastly compared to the field data. All these results challenge the current industry's understanding and best practices for through-tubing drillouts in the Montney and Duvernay formations. With the contentious increase of lateral lengths and higher stage counts, the process of drilling out frac plugs has become more complex. This study explicitly benefits all operators in their ever-increasing need to understand their frac plug drillout operations to ensure efficient, cost effective, and most importantly, consistent and repeatable results. While efficient results for frac plug drillout operations have been accomplished to date, the on-going feedback from the field has been the requirement to produce repeatable drillouts. This paper is the first to show a holistic approach for obtaining a transient debris transport model used for through-tubing drillouts of frac plugs. The novelty also consists of the transient debris transport model validation through laboratory data and actual Montney and Duvernay field data.

A mathematical model is developed to capture the dynamic features in the wellbore during drilling operations so that it could be used for real-time computations. The model comprises one-dimensional (1D) mud flow solvers, one for the drillpipe and the other for the wellbore annulus including the volume below the drill bit, integrated point models for the bell nipple, bottomhole assembly (BHA) nozzles, 1D shallow water model for the flowline, and point model for the bypass replicating the hydraulic circuit in the drilling rig. The model assumes compressibility of mud for the wellbore section along with its transient gel characteristics. The equations are solved using appropriate explicit numerical solvers and the results capturing the fast transients of the standpipe pressure, bottomhole equivalent circulating density (ECD), and the flow rates during dynamic drilling operations are presented to illustrate the performance of the model with field data.

Effective well control depends on the drilling teams’ knowledge of wellbore flow dynamics and their ability to predict and control influx. Detection of a gas influx in an offshore environment is particularly challenging, and there are no existing datasets that have been verified and validated for gas kick migration at full scale annulus conditions. This study bridges this gap with the newly instrumented experimental well at PERTT (Petroleum Engineering Research & Technology Transfer Lab) at Louisiana State University (LSU) simulating an offshore marine riser environment with its larger than average annular space and mud circulation capability. The experimental setup instrumented with fiber optics and pressure/temperature gauges provides a physical model of the dynamic gas migration over large distances in full scale annular conditions. Current kick detection methods do not always reliably detect a gas influx and have not kept pace with the increasingly challenging offshore drilling conditions. Even though there have been some recent developments in offshore kick detection, all methods thus far are only qualitative in nature because they are based on measurements at the surface. This study addresses current kick detection limitations and illuminates the potential for implementing distributed fiber optic sensing (DFOS) to the marine riser as a non-invasive and effective kick detection method in both stagnant and circulating annular conditions. As North America's only academic full scale well testing center, an experimental well in the PERTT lab was utilized to monitor and characterize gas rise using DFOS to simulate well control scenarios in offshore drilling riser environments. DFOS allows for the tracking of the gas migration in both the stagnant and full-scale circulating annulus conditions. Data from pressure sensors is integrated with the distributed temperature (DTS) and acoustic (DAS) measurements, for real-time downhole monitoring of the dynamics of the gas migration and fluid front movement. By implementing time and frequency domain analysis of the fiber optic data, we show that the gas rise and water front movement can be identified. Both the water and gas injection down the tubing independently show characteristic fronts in the DTS and DAS data, which gives us confidence in our interpretation. Once the gas is present in the annulus, the DAS measurements indicate a higher than expected gas-rise velocity, and this is most probably due to the full-scale annular geometry and circulating conditions enabling a faster gas rise velocity compared to previous work in this area consisting only of small-scale experiments and experiments through tubing. The two-phase flow experiments conducted in this research provide critical insights for understanding the flow dynamics in offshore drilling riser conditions, and the results provide an indication of how quickly gas can migrate in a marine riser scenario warranting further investigation for the sake of effective well control.

Since the 1970s, 12 deep vertical gas wells in the Thomasville area in Mississippi, USA have been producing high volumes of sour gas (3 to 21 MMcf/D per well). This production decreased to unsustainable levels, which required the field to be abandoned. Abandonment presented a rare combination of challenges including high temperature (>400°F), high sour gas and CO2 (more than 40% H2S and up to 9% CO2), depleted formation (0.1 psi/ft), scale buildup, unique well geometry, true vertical depth ranging from 20,300 ft to 23,600 ft, and nearby residential areas. A combination of special operating procedures, intelligent self-healing cementing slurries, and novel placement techniques enabled the wells to be successfully abandoned with layers of contingency to prevent a catastrophic environmental release. The plug and abandon operations were divided into two phases. Phase 1 was rig-less operations to kill the well and isolate the formation by using an engineered ultralightweight 9.0-lbm/gal cement slurry that provides greater corrosion protection compared to a normal cement slurry. Novel placement techniques were used to place the engineered slurry across the production perforations and open hole to isolate both the tubulars and annuli. Advanced hydraulic simulations were run to model the complex placement. A traditional drilling rig was moved in for phase 2 of the operations. In phase 2, intelligent cement plugs, which included flexible and self-healing properties, were placed to add greater zonal isolation assurance accounting for unknown well conditions for the long-term abandonment of the well. Cement plugs were verified with robust negative and positive pressure tests. It was determined that an ultralightweight slurry could be placed with a 0.1-psi/ft fracture gradient using nitrogen displacement, optimized slurry volume, and variable choke to regulate pressure on the backside to isolate the wellbore. Displacing with nitrogen proved to be challenging, and the many lessons learned will be documented in this paper. All 12 of the producing wells, along with 5 disposal wells in this field, were successfully killed and plugged. To date, none of the wells are showing pressure. This paper will review the challenges faced with designing a successful P&A program in this Thomasville area. Both phases of the final operations will be presented, and lessons learned along the way will be discussed. These complex well conditions were overcome through sound designs in operational planning, cement slurry optimization, placement techniques, and isolation testing methods. The primary plug proved to be effective at being placed in a depleted environment and at ultrahigh temperatures while taking into account corrosion protection. The intelligent cement slurry offered long-term barrier assurance through both failure prevention and self-repair. The long-term solution outlined in this paper is key to preventing a catastrophic environmental release. The innovative placement techniques, contingencies taken, and lessons learned during the campaign will be useful to other technologists in other fields faced with similar conditions.

The Perforate, Wash and Cement technique has been widely applied to remediation of annular cement in recent years. Since 2012, extensive experience in the different technologies currently available on the market has been obtained across ten fields in the Danish and UK sectors of the North Sea and the data obtained has been used to attempt to better understand the effective operational window for the technique, and also further enhance reliability and tool robustness. The run data obtained from several wells has been calibrated against cement bond logging (CBL) responses so that the degree of annular bonding as inferred from the logs may be expressed in terms of the degree to which hydraulic communication or circulation is permitted via perforations and along the annulus. This in turn helps clearer decision criteria to be defined prior to execution that aids in the selection of the most appropriate method for remediating the cement, since Perforate, Wash and Cement may not be the most suitable technique in every case. Given the criticality of cement remediation to the long-term success of zonal isolation, it is important to demonstrate that effective hydraulic communication with the annulus has been established during the washing phase to ensure that the zonal isolation medium (cement) can be effectively placed and the hydraulic seal re-established, resulting in successful remediation. Post-execution verification of the effectiveness of remediation is typically performed via Cement Bond Logging. However, this may not always be a definitive verification step since Cement Bond Logging interpretation does have its limitations (both physical and interpretative), and hence annuli have occasionally been known to develop Sustained Casing Pressure even shortly after positive log interpretations following well-executed cementations. This paper therefore further demonstrates how Sustained Casing Pressure monitoring can be used as a further criterion to verify the integrity of the remediated annulus and hence conclusively demonstrate whether the washing and later cementing of the annulus has been effectively performed. This in turn is used as definitive confirmation that zonal isolation has been performed within the operating limits of the tool and hence qualify Perforate, Wash and Cement as a robust and viable remedial method.

Effective zonal isolation is critical in lost circulation, cement repair and conformance applications. To be successful it is often necessary to not only block pathways but also ensure a tight seal. Gaps or weak points between the blocking material and boundary layers can result in poor zonal isolation leading to gas migration, gas entrapment, and/or excessive water production among other issues. The mechanisms vary but cement, polymers, and sodium silicate can all lose volume upon setting and aging. The degree of contraction being impacted by downhole events such as fluid loss, influx of gas, water or conditions such as high temperatures In the case of Portland cement, several different methods have been developed to ensure dimensional stability. A long time approach has been the addition of aluminum powder to the cement slurry for the in-situ generation of hydrogen gas. This paper looks at how elemental aluminum as well as zinc can be adapted for use in a sodium silicate-based system. In developing a new technology, several questions are posed at the onset. At the top of this list are the health, safety, and environmental implications of the individual components and final product. Fine powders are inherently dusty and carry an explosive risk if not properly handled. Development of a safe form of the metal powders became the first priority. The direction taken was to slurry the metals using suitable base oils and mutual solvents. As part of the slurry development, the shape and size of the aluminum and zinc were studied for resistance to settling, rheological stability, and reaction kinetics. Stable metal slurries could be formed in base oils such as polyalphaolefins or mineral oils when combined with other additives. The selected base oils were shown to function in a similar manner as encapsulators and be used control the rate of the gas generation reaction. Mutual solvents such as triacetin provided further functionality by being able to initiate a polymerization reaction of alkali silicate. Short-term properties such as set time, density, rheology, and compressive strength were made adjustable by concentration and the use of filler/bridging material such as walnut hulls, glass powder, calcium carbonate, barite, or fly ash. While sodium silicates can be set by either an internal or external setting agent, the industry preference is for a one component system. Presented in this paper will be the development of a one component system that safely incorporates the in-situ generation of hydrogen to yield a chemically durable, mechanically strong expanded silicate-based plug.

Extended reach drilling well design is one of the most critical designs to consider for achieving maximum reservoir contact and increasing well production. This paper demonstrates the methodology for delivering an organophillic clay-free, invert emulsion fluid system using calcium bromide in the internal phase, and discusses an innovative breaker package containing an acid responsive surfactant. Results show a significant reduction in metal/metal and metal/formation friction. Furthermore, no change in wettability has been recorded after the formation has been treated with the breaker. Precise quantitative and qualitative testing methods provided milestone results. Phases of design began with API testing, followed by stressing the fluid beyond the normal downstream conditions, then finally using the return permeability apparatus. Testing all fluids against an artificial core, followed by a natural core, gave the operator the projections required to drill such complicated wells. Intelligent software helped to replicate the actual conditions precisely enough to drill and complete these wells with minimum friction, as well as to simulate effective hole-cleaning practices to help enable optimum equivalent circulating density (ECD) management. From planning to execution, valuable observations were recorded. The use of this system resulted in successfully drilling and completing the longest horizontal well in offshore Abu Dhabi. During 2.5 months of drilling and completing time, no critical path time was wasted because of uncertainty or changes to the approved plan. As a result of using non-aqueous fluid, the friction factor was reduced to 0.07. Furthermore, no fluid treatment was necessary to maintain that lubricity beyond the physical properties of the system itself. The unique composition of the delayed acid breaker used in combination with acid responsive surfactant removed any skin or crushed zone around the wellbore. The recorded well producibility was beyond the expectation, and no acidizing was required. For nearly a decade, lubricants associated with water-based fluid types have been engineered, but inver emulsion fluids had not been considered because of their low initial density and issues associated with stimulating the reservoir. This system provides a successfully designed and executed organophillic clay-free, invert emulsion fluid, as well as a state-of-art delayed acid filter cake cleanup package to maximize the return on investment.

Reverse circulation cementing is a placement technique that reduces bottomhole equivalent circulating densities (ECDs) and reduces lost circulation risk in wells in which conventional circulation pressures would break down formations. Until now, reverse circulation cementing has been performed only on land or in shallow-water wells in which the annulus was accessible from the surface to pump down. This paper describes the design, development, and validation of technology that enables subsurface reverse circulation. Gaps in technology have made it challenging to transfer reverse-cementing-placement techniques to primary cementing operations in deepwater. To reverse cement a liner, fluids must be pumped down the work string to prevent potential contact inside the riser and blowout preventer (BOP), and then fluids must be injected into the annulus downhole while full circulation continues. A tool system was developed to facilitate this unique flow path, provide alternative methods to set liner hangers, and provide flexibility for contingencies and other operational requirements. The developed subsurface reverse circulation tool system uses radio frequency identification (RFID) technology so that the tools can be operated remotely and repeatedly either by RFID tags or through surface-pressure pulse sequences. Three RFID-activated tools were designed: a circulation tool, a crossover tool, and a downhole flapper. The prototype tool system was first evaluated through bench testing of individual components and then through large-scale rig testing. During the rig trials, the entire system was run into a test well, and a multiday sequence of flow testing validated the function and performance of each tool. After successful testing in rig trials, the subsurface reverse circulation tools (RCT) were deployed in the Appalachia basin field, located in the Northeastern United States. This paper discusses the requirements of a subsurface reverse-circulation-cementing system. It describes the design, development, and validation of technology that enables subsurface reverse circulation. It also describes the prototype system that was built and the field testing results. This new capability enables the cement to be pumped down the work string and then to exit to the annulus at a point above the liner string.

Realizing the potential benefits automation brings, many operators have turned to managed pressure drilling (MPD) techniques as a technical and cost-reward solution to hard-to-reach assets, an approach which not only saves time but also enhances the safety capabilities of the operation. The evolving industry shift toward MPD-ready rigs demonstrates the significant need for a reliable software system to interact with the equipment and simultaneously deliver enhanced models able to precisely control annular pressure in geological complexities where drilling windows are narrow. Several studies have demonstrated the operational benefits of MPD through the application of the constant bottom hole pressure (CBHP) method, imbedded automated kick detection, and control capabilities. MPD technology relies substantially on applying surface back pressure (SBP) using automated chokes to precisely control the annular pressure profile in a closed loop circulation system. During drilling, CBHP connections, mud displacements and fluid anomaly incidents, the SBP is dynamically adjusted in response to operational changes that yield annular pressure changes; such as circulation rate, top drive speed, and rate of penetration to name a few. The integrated MPD drilling software platform is used in combination with interactive models and surface and downhole data measurement in a unified computing system to enhance real-time analysis of drilling performance. By employing real-time models such as hydraulics, well control, pore and fracture pressure estimation, surge and swab, and drilling optimization torque and drag, the system quantifies the boundaries and aid in understanding the real operational limits. Additional software platform applications deliver the common integration baseline that enables both operations within the pre-drilling, while drilling and post analysis. The current automated MPD software has been successfully used in several onshore and offshore wells with narrow drilling windows. This paper discusses the applications and the newest developments in the MPD integrated software to automatically and precisely manage wellbore pressure. The results to be presented include the summary of planning, while drilling analysis, and post drilling analysis of an offshore case study where a detailed parametric analysis of measured and estimated data are compared.

Managed pressure operations enable keeping the equivalent circulation density (ECD) within a narrow pore-frac pressure window during drilling and cementing while maintaining the wellbore stability and controlling formation pressures. The operation becomes more complex during a cementing job, where fluids with different density and rheology parameters are pumped downhole at varying rates, resulting in different friction pressure profiles. Proper numerical simulators must be used to model such variations and keep the downhole pressure between the pore and fracture pressures during the operation. Managed pressure techniques and technology were critical to the successful cementation of the 7-in. liner at 12,000 ft. in a gas field in Saudi Arabia, across formations ranging from a high-pressure zone with 2.36 SG (19.65 ppg) formation pore pressure to a depleted low-pressure formation with 2.44 SG (20.32 ppg) fracture pressure. The challenge in this job was to maintain the ECD at 2.40 SG (20 ppg) throughout the cement job to avoid any losses or flow from the formations. An automatic choke setup on the return flow line with a dynamic control system was used to drill the 8.375-in. open hole with KCl polymer mud. Precise cementing simulation was used to determine the ECD during cement placement. Numerous pre-calculations and simulations were run to evaluate various scenarios prior to the cement job to ensure effective manipulation of back pressure through managed pressure drilling (MPD) equipment to maintain ECD at the desired value throughout the cementation process. The detailed simulations run by cementing and MPD engineers prior to the job and a collaborative approach were instrumental in defining a final cementing plan, completing the layout of equipment used for the cementing job, and executing the job with real-time monitoring of all critical parameters affecting ECD and evaluation of the cement job.

As Operators are increasingly seeing the value of in-well monitoring in optimizing production and reducing interventions, Operators are demanding greater accuracy, reliabilty and timeliness of well information above what is available today. This study explores a new method of measuring temperatures in harsh downhole environments that aims to improve on some of the limitations of conventional distributed temperature sensing (DTS). Instead of using Raman backscatter signals to infer temperature, a calibrated fiber Bragg grating (FBG) array is used to measure the temperature. Bragg gratings have previously been deployed as temperature measuring devices, usually as discrete devices individually spliced in a cable. The cable design presented in this study reduces deployment costs compared to discrete Bragg gratings, and can also scale up to 1000 gratings. Additionally, an interrogation method has been developed for measuring the wavelengths of the FBG array. Traditional swept-wavelength interrogation techniques exist to measure FBG arrays, but they are typically limited to approximately 40 gratings. Like the cable, the interrogation method scales up to 1000 gratings at 1 meter grating spacing. Numerous system performance tests were conducted in a laboratory setting and in a simulated well environment. A prototype cable was deployed in a test well alongside a standard DTS cable. The cables were exposed to temperature cycling by circulating hot and cold fluid. Measurements produced by the two cables were recorded and analyzed. The prototype cable test results demonstrated that the grating cable is capable of higher resolution temperature measurement than conventional DTS. The prototype interrogator will be able to perform the measurement in less than 10 seconds, a fraction of the measurement time required by conventional DTS interrogation. Results from other tests have demonstrated the ability to perform well with long lead-in distances without losing accuracy. With this increased range, the interrogator can be located away from the wellhead and in offshore wells, above water.

Production liner cementation in deepwater wells is critical to contain formation pressures and provide zonal isolation. This is especially challenging in the Gulf of Mexico because of depleted zones, small drilling margins, and HPHT reservoirs. Failure to achieve zonal isolation with the primary cement job leads to added cost and time for remedial operations. A recent primary cement job failure in the Viosca Knoll Block, located in the Gulf of Mexico, prompted the use of an established tool, Root Cause Failure Analysis (RCFA), in a novel way to identify the causes of the incident and avoid repeating the same mistakes in future wells. A team of operations and engineering personnel was assembled to investigate the cause of the primary cement job failure that resulted in nonproductive time and cost of approximately 7 days and $3 MM, respectively. RCFAs have typically been performed on equipment failures; however, this RCFA was conducted by the operator on a non-equipment related failure. The RCFA team initially collected data available from both the planning and operation phases of the job in order to identify which elements of the cementing process contributed to the cement job failure. After identifying the root cause, the team communicated learnings to office and rig-based personnel, developed a new tool for real time monitoring of primary cementation, and adjusted plans for upcoming primary cement jobs. The findings from the RCFA were applied to a well on another asset owned by the operator, with which the production liner was successfully rotated throughout cementation for the first time. The RCFA identified that the cement job design was not a contributing factor; instead, the root causes were operational and started during circulation of drilling fluid prior to cementing operations. The learnings from the RCFA were transferred to both office and rig-based personnel, influencing engineering and operations plans for subsequent wells. Furthermore, the investigation identified previously unknown issues and showed that the use of the RCFA process was an effective approach that can be standardized and scaled to determine root causes of future operational failures.

The subject High Pressure High Temperature (HPHT) well proved extremely challenging with reservoir BHT of 334°F and approximate 13, 900 psi reservoir pressure. Managed Pressure Drilling (MPD) was originally selected to avoid a classic "Kick-Loss-Kick" scenario while drilling deep Austin Chalk formation wells in East Texas. While a secondary goal of MPD ("to ascertain the downhole pressure environment limits") was accomplished, the greatest benefit of MPD was seen while handling several well control incidents that occurred in the HPHT reservoir section. Optimal control of these incidents was facilitated by modification to the MPD technique and reconfiguration of the BOPE to allow for more appropriate application of the MPD equipment. During drilling, a combination of high temperature and fluid properties (drilling fluid and reservoir fluid) resulted in repeated failures of the annular preventer and at least one variable bore ram (VBR) element failure at low pressure relative to the equipment rating. Ultimate integration of BOPE and MPD equipment allowed drilling with MW at or near balance to reservoir pressure. Following and during trips, allowance had to be made for mud property changes caused by heating or cooling effects at both the surface and downhole. The mud property changes affected Equivalent Circulating Density (ECD) while drilling and tripping. Mud monitoring proved critical. As HPHT and drilling technology mature, the line between flow control and well control begins to blur. Rather than transitioning from one to the other and back, the drilling and well control activities tend to become parts of a single process. This process, as described in the paper, must take into account the effect of variations in drilling fluid properties. Knowledge of the exposure limitations to pressure, temperature and other parameters and the effects on composition of pressure sealing elements in all surface and downhole tools is critical. The operator must also account for the effect of HPHT on specialty equipment such as RCDs, extra choke manifolds or manifold elements, and additional monitors. Adjustments in utilization and acquisition of slow pump rate information, use of the entire active pit system while circulating out kicks, and handling uncertainties in the downhole pressure regime are also part of this process. How alternative casing design affects well control while circulating a kick (influx) and using other unconventional drilling techniques will also be described.

Failure to minimize lost circulation can greatly increase the cost of drilling and the risk of well abandonment. The main reason why some of the remedial procedures are not working as planned is the lack of information in loss zone locations. Inaccurate estimation of loss zone location prevents the treatment to be applied directly at the point of loss, results in low efficiency and extended nonproductive rig time. This paper describes an approach for identifying the location of loss zones in directional wells using distributed temperature measurement while drilling. A transient thermal model for predicting the temperature profile in a directional well with mud loss is presented. The numerical solution under different lost circulation conditions, when used together with the distributed temperature measurement, can identify the location of mud loss. For a deep high pressure high temperature well with severe lost circulation, there is a significant change in the thermal behavior of the wellbore as mud loss continues. The characteristics of wellbore thermal behavior are evaluated and identified as good indicators of loss zone location. The distributed temperature measurement while drilling is enabled by a drilling microchip technology that has been developed and validated with successful field tests. By matching simulated results with the distributed temperature measurements at different timestamp, the depth of the loss zone can be accurately identified. Case Studies are given to show the practical applications of the method. The results are important in applying expandable tubular system, setting cement plug and spotting lost circulation pills. An additional application of this approach is the identification of highly permeable zones for reservoir or formation evaluation.

A multitude of challenges exist when cementing production liners for deepwater operations. In many platform operations, cutting windows to sidetrack and drill highly deviated well paths to intersect reservoir targets result in difficulty obtaining adequate casing standoff due to tight inside diameter (ID) restrictions from previous casing architecture. Many of the zones near the target interval may have significant pressure depletion which can lead to expensive Synthetic Based Mud (SBM) losses and associated non-productive time (NPT). The size of the production liner is dependent on the wellbore architecture and completion plan. Thus in most cases, the borehole must be under-reamed in order to provide for adequate cement sheath thickness. In these cases, centralizer selection and placement can be challenging or all together impractical. Cementing in SBM environments has also been traditionally more challenging because special considerations for spacer/surfactant/mud design and testing are required to effectively displace the mud and "water-wet" the formation/casing for good quality cement-bonding. Technology improvements in spacer and surfactant package formulations provide a more qualitative method for optimum surfactant design to maximize mud removal and provide a bonding surface to the formation. Liner hanger selection may not always provide the capability for pipe rotation which has shown to be very effective for mud removal and increased circumferential cement coverage. Without pipe rotation, additional key techniques for successful cementation must be prioritized. A process driven decision matrix is presented along with a recent selection of successful production liners to support the design concept.

Solids removal from severely depleted wells remains a challenging intervention operation in the oil and gas industry. The various cleanout options that exist generally require significant expense, and may result in loss of potentially damaging fluids or permeability reduction to zones with low bottomhole pressures. This paper will focus on several field trials in South Texas utilizing a fluid-based, formation-blocking agent as part of the cleanout circulating fluid. The blocking agent has been in use for several years in cement spacer systems as a lost circulation material (LCM) with favorable results. The blocking agent uses a modified, hydrophobic polysaccharide to form micelles. Under differential pressure the micelles adsorb and realign in a layer along the formation or perforation tunnel forming an impermeable seal effectively blocking the loss of fluids to the formation. With the formation blocked, the solids can be circulated out using a higher density fluid and at higher circulation rates than the low-pressure reservoir would support. When the well is returned to an underbalanced system, the micelles will disperse, returning the fluid to its original state and restoring permeability to near a pre-intervention level. The case histories included in this paper are the first application of this material for well intervention operations outside a cement spacer application, and the results discussed show that the material performed remarkably well.