SPE/IADC Drilling Conference and Exhibition

Following the success of the first installed intelligent completion system in Saudi Arabia in 2004, over 260 Intelligent Completion systems have been installed in a majority of Maximum Reservoir Contact (MRC) Multilateral (ML) wells. These intelligent completion systems have been successfully installed in openhole, expandable liners, expandable sand screen, Extended Reach Drilling (ERD) wells and also integrated with Electric Submersible Pumps (ESP). This technology has led enhanced oil recovery while reducing water production to surface. Water handling cost at surface is reduced by producing less water to surface and also shutting off downhole water production completely.

This paper covers some of the case histories of over ten (10) years of design, planning, installation, testing and optimization of intelligent completion systems in Multilateral (ML) Maximum Reservoir Contact (MRC) wells within Saudi Arabia. Production optimization practices and enhancement of production life in carbonate multilateral wells in the world's largest oilfield are also documented. Case histories highlighting how water production was remotely choked back, shut-off and production optimized from identified lateral without any intervention in the well are reviewed.

Advantages of intelligent completion technology for multilateral wells and the review of the downhole choke customization process that included design flow area after modelling well data for different flow rates and differential pressures are detailed. This is in addition to the integration of the surface control system to the production supervisory control and data acquisition (SCADA) system which provided real-time downhole pressure and temperature data and remote control of downhole flow control valves during the life cycle of the well. This paper also discusses a closed-loop approach which led to efficient real time production optimization. Performance review of how intelligent completion systems provide selective lateral control, delay water breakthrough, control water production, shut off wet lateral, reduce opex, optimize production, enhance recovery and reduce safety risks thereby minimizing future interventions are documented.

A wide variety of annular pressure buildup (APB) mitigation techniques have been deployed in the past two decades. In the early 2000s, BP focused efforts on the development and implementation of rupture disks, nitrified foam spacers, syntactic foam modules and vacuum insulated tubing (VIT). Initiatives to simplify operations while maintaining well integrity have led to innovative techniques which expand the APB mitigation toolkit.

BP's Gulf of Mexico Thunder Horse drilling team has recently pursued three APB mitigation techniques. One method is to fully-cement the annulus, thereby removing the fluid that is subject to thermal expansion in a trapped annulus. A second method uses a qualified port collar to equalize pressure across a casing string. The third method focuses on better acquisition and utilization of mud pressure-volume-temperature (PVT) data for a more precise prediction of the APB design loads.

These methods and techniques have led to the removal of syntactic foam from some wells in the Thunder Horse field. The design change reduces installation time and operational complexity during well construction and abandonment.

This paper provides a description and technical details around the planning and job execution for the fully-cemented annulus and the use of port collars for pressure equalization. It also discusses the motivation behind acquiring PVT data specific to a particular mud system and provides interpretation of laboratory data. The work may be useful for other operators as they plan and execute wells subject to the potential for APB.

Hydraulics can significantly affect Polycrystalline Diamond Compact (PDC) bit performance in applications where cuttings volume, formation types, and rig pressure limitations lead to poor fluid dynamics that compromise cleaning and cooling, and result in lower ROP and higher bit wear. A key mitigation challenge is improving cleaning efficiency without experiencing a significant pressure drop across the bit. This paper studies hydraulic conditions affecting PDC bit performance, examines modeling and design steps to develop a curved nozzle design, and presents the nozzle's performance in the field.

Research including computational fluid dynamics (CFD) modeling was conducted to better understand flow and velocity across the bit face. The resulting curved nozzle geometry was complex and required multiple iterations to achieve the desired effect. The nozzle design was applied in the field and its performance was compared to similar PDC bits with standard nozzles.

The curved nozzle design redirects fluid flow and reduces distance from the nozzle outlet to cutting face while retaining the same total flow area (TFA). The change in flow characteristics increases fluid impact on the formation and velocity in the waterways to enhance cleaning efficiency and cooling. The carbide nozzles were manufactured and installed on standard PDC bits used in a series of Permian Basin vertical and lateral wells in the United States. Vertical applications in Canada's Viewfield field were also studied. Bits fitted with the curved nozzles demonstrated significant performance gains compared to bits with conventional nozzles. Field reports show higher ROP and less bit wear in formations where interbedded clays and reactive shales present hydraulic challenges.

The insights gained into PDC bit hydraulics and the performance of the resulting curved nozzle design has enhanced the ability to mitigate many common hydraulics-related cleaning and cooling challenges.

In many instances subs and stabilizers are bored to be used with a float valve in a box connection facing up-hole rather than down-hole. Sometimes the requirements for float bore depth, which are derived for a "box-down" float bore, are not sufficient to ensure the proper sealing of the float valve within the float bore in this "box-up" configuration. Additionally, regardless of float bore orientation, there is a chance that the float bore depth requirement can be long enough that the float bore runs into the pin connection of the sub on which it is machined. This can result in high stress in the float bore which could lead to fatigue cracks and a reduced load capacity of the tool due to a decrease in cross sectional area.

This paper details the design methodology used to ensure the proper sealing of float valves used in box-up float bores. Finite element analysis (FEA) was conducted to determine the distance from the back of the float bore to the shoulder of the pin connection necessary to substantially reduce the stress experienced as a result of connection make-up forces.

The new design methodology ensures proper sealability of float valves and structural integrity of the tool. New requirements based on this methodology have been implemented by various manufacturers and vendors with successful results.

A case study is provided which describes how a gap in current industry accepted inspection practices led to a sub with a float bore that was machined long enough to reach the shoulder of the pin connection to be overlooked. This led to the failure of the sub downhole. The paper provides a reasoned approach to new criteria needed for float bore design and makes the case for the standardization of float valves.

Tubular connection integrity is a key to short-term and long-term well integrity. The stress on the tubular and the connection, particularly in high-pressure, high-temperature wells, creates challenges for connection providers. Proper selection of makeup method is essential to achieving long-term performance of premium connections.

The tubular running process comprises the use of a tong to make up and break out connections. Over the years many different tong types have been developed, from manual tongs to fully mechanized power tongs. The torque reaction system in the tong plays an important role in providing optimum torque to the connection, which depends on how well it eliminates undesirable side forces on and bending of the connection. Side forces create high friction on the threads that can cause the measuring system to provide an incorrect torque reading, which can result in an undertorqued connection. The friction and compressive forces can also introduce thread galling problems that affect connection integrity.

To evaluate this phenomenon, laboratory tests were performed on a 5.50-in. premium connection joint using two power tongs with three different torque reaction systems (free-floating backup, integral backup, and snub line). Strain gauges and 3D-optical strain measurements were used to analyze forces and deflection acting on the connection during makeup. Results indicate higher side forces and bending on the connection when using integral backup and snub line configurations; however, the free-floating backup system reduces these forces significantly.

This paper first highlights the importance of pipe connection integrity and the consequences when it is compromised and goes on to provide a comparison of the three torque reaction systems and their effect on the connection.

The paper addresses the gas loading characteristics of the drilling fluid and its influence of the gas influx rate during the flow check operation. In particular, the resulting fluid expansion in the wellbore annulus and the capability to detect gas kick at HPHT process conditions will be discussed for selected drilling fluids.

For the evaluation of the applicability of flow check operations for the detection of gas influx, the time response to the drilling fluid expansion during natural gas influx is addressed in terms of drilling fluid gas loading properties, influx severity and influx area.

The physical gas loading rate of natural gas into the drilling fluid is described as a first order kinetic mass transfer process including the gas loading capability for the multicomponent system of drilling fluid and natural gas, in addition to the gas influx characteristics at the wellbore–formation boundary.

When operating the fluid system of natural gas–drilling fluid in the liquid phase region, a continuous gas influx will at some point give more distinct expansion of the fluid mixture in the wellbore. This occurs for the maximum gas loading of the drilling fluid. Such distinct change in sensitivity in the volume expansion response is not encountered when operating the system of drilling fluid–natural gas in dense phase. For selected cases relevant for HPHT drilling, the volume expansion response during flow check operation is compared for drilling fluid with gas loading characteristics either representing single liquid phase or dense phase gas loading. With the methodology described it is readily shown that the interpretation and design of the flow check operation should be carefully selected when approaching dense phase conditions or if the gas loading capability of the drilling fluid is considerable. This is particularly important for oil-based drilling fluids featuring high gas loading capability.

Human Factors encompass elements which influence our behaviour. In a work environment they embrace many areas, for example; environmental and organisational, the design and functionality of equipment, process and procedures, individual characteristics of personnel, their skills and competencies.

It is generally acknowledged many of the world's worst oil field incidents have been attributable to Human Factors including well control events like the Montara and Macondo blow outs and many others. It is notable that some well control incidents initially appear straightforward but are frequently exacerbated by human error, increasing risk and costs, and in the worst cases resulting in blowouts.

The oil field has been a little late in realising the importance of Human Factors but there is now recognition they are essential in successfully resolving well control events. The inclusion of Human Factors in managing well control events was also a recommendation of the OGP 476 report in 2012.

The corporate well control manual was refreshed to include Human Factors in the management of well control incidents. This required mapping the well control process, assigning personnel specific roles, defining contingencies, etc. whilst acknowledging the effect Human Factors has on the personnel involved. The intention was not to create a rigid structure but to rather provide a framework to guide the front line in dealing with a well control event. New policies and procedures were subsequently developed and included in the update.

It is recognised this new philosophy will require an ongoing commitment impacting well control procedures, client liaison, bridging documents, the assessment and assurance of teams, well control training etc. It is further acknowledged this is just a first step and there will be continued development and refinement of the management tools as the system beds in.

In a Deepwater well off the Brazilian coast which presented a complex architecture with multiple drilling casings and liners, losses were expected during cement placement across a carbonate formation. This paper describes the use of a new real time monitoring and evaluation tool which takes the data acquired during the cement placement, then processes and simulates in real time to provide important job parameters such as estimation of fluid interface positions inside the casing and annular space, pressure match chart, density quality assurance and quality control (QA/QC), ECD and dynamic well security, among others.

This manuscript present two cases history where the operator and the service company work together to define a decision tree for the possible contingencies related to unwanted TOC based on mud losses or unplanned cement placement. Later during the operation the new tool combines the design data with the cement unit and rig acquisition data to compare the job measured surface pressure, density, flowrate and volume with predicted data from simulations. Finally based on the information of real time estimation of the TOC outside the pipe and annulus space observed during the job execution a contingency from a decision tree is taken.

The cementing service company provided real-time monitoring and evaluation tool that allowed the operator to identify the estimated TOC at the end of placement. With this information, the client was able to avoid the top of liner squeeze and save 2-3 days rig time Later a cement bond log showed that top of cement was found between the liner lap confirming the barrier element. In another case it was prevented leaving unplanned cement inside the casing with the analysis of the job and simulated pressure match trends at the end of the displacement and eliminated unexpected flat times for additional drill out time.

Real-time monitoring and evaluation is a tool that can be deployed not only in Deepwater wells in Brazil, but in any section of wells being drilled around the world on land, on the shelf or in Deepwater, where the operator wants to visualize ether the deviation of job execution from job design parameters or a prompt estimation of top of cement as a first level of detection for the well barrier placement just after bumping the plug. In addition having the real time dynamic ECD will also aid in avoiding any potential well control situations (including lost circulation) during the cement operations at any time during this critical activity

Annular pressure buildup (APB) is a major concern in high pressure, high temperature (HP/HT) well design. High temperature hydrocarbon production increases wellbore temperature significantly, inducing a large APB as a result of annular fluid thermal expansion. Vacuum-insulated tubing (VIT) can be used to reduce the annulus temperature increase to mitigate APB. However, because of the natural differences between VIT and standard pipe, there is uncertainty about accurately modeling the VIT wellbore temperature distribution and its effect on APB.

The VIT vacuum section has much better insulation than the connector, which induces a nonuniform heat transfer that generates significant annulus temperature spikes along the axial direction, up to 50°F in half-VIT unit length (20 ft) (Gosch et al. 2004). Conventionally, the axial temperature gradient is ignored because it is negligible in comparison with radial temperature gradients. This assumption is no longer applicable with VIT because these temperature spikes significantly enhance natural convection. This study presents a novel wellbore heat transfer model that considers nonuniform heat transfer and enhanced annulus natural convection to provide accurate VIT well temperature predictions and APB estimates.

Operators use overall average thermal conductivity over the VIT because it yields an acceptable conservative incremental pressure in APB calculation that matches field observations. In addition, there is uncertainty about simply modeling VIT in a conventional simulation method with different thermal conductivity values for the vacuum section and connector. This study captures the VIT nonuniform heat transfer behavior. The temperature spikes enhanced natural convection is considered for the overall wellbore heat transfer modeling. Case studies show that temperature spikes in the annulus are observed in which the temperature distribution pattern closely matches the field measurement; the spike amplitude decreases, as compared with a conventional simulation method in which the axial natural convection is ignored. The average annulus temperatures also increase significantly. This result indicates that the conventional simulation method considerably underestimates the temperature and APB. In addition, whether or not the connection is insulated plays a critical role in overall VIT performance. Good connector insulation increases the overall insulation and APB mitigation significantly. The level of the connector insulation on the VIT overall insulation performance and APB mitigation quality are also studied and reveal that the connector thermal conductivity value at 15 times that of the vacuum section is an effective and economic insulation level.

Literature surveys show very few studies that consider this enhanced natural convection effect in VIT wellbore temperature and APB estimation. A conventional wellbore temperature simulator ignores this effect and underestimates the overall wellbore temperature and the APB. This paper provides a novel solution model for VIT wellbore temperature prediction and APB analysis, which will be useful for advanced casing and tubing design.

An operator experienced sub-optimal drilling performance in a multi-rig, multi-well drilling campaign in the Sultanate of Oman. This paper describes collaboration between the operator and a bit vendor to establish key operating parameters for efficient drilling based on fundamental drilling mechanics and laboratory testing. The concept was implemented and validated in that field's 12 ¼″ section.

The method makes minimum weight on bit (WOB) and torque recommendations based on the observation that a critical depth of cut (DOC) should be exceeded if a polycrystalline diamond compact (PDC) bit is to drill efficiently. Below this DOC the drilling efficiency, which is inversely related to the mechanical specific energy (MSE), can decrease significantly depending on the rock strength and the downhole environment. This behaviour has been associated with a transition between shearing and grinding as the predominant rock destruction mechanism. Critical DOCs and corresponding WOB and torque levels were determined from a wide range of laboratory drilling tests in carbonate rocks. Initially bit design details and anticipated formation properties were used before a bit run to develop minimum WOB recommendations and torque targets which were communicated to rig site personnel in a run-specific drilling roadmap. Rig crews were encouraged to maintain WOB above the minimum whenever possible while avoiding damaging stick/slip vibration and observing pre-agreed bit, bottom hole assembly (BHA) and rig imposed limits. Later the pre-drill recommendations were supplemented by computing the real time instantaneous DOC during drilling and comparing this with the critical value for efficient drilling to indicate whether the current WOB should be increased.

Sub-optimal performance in early wells was frequently associated with parameters insufficient to achieve the critical DOC and torque. Penetration rate performance showed a significant and consistent improvement after adoption of the roadmap. The section average penetration rates increased by 45% and routine shoe to shoe bit runs were achieved where previously an average of 2.6 bits per well were required for this hole section. We conclude that ensuring DOC and torque exceeded the thresholds for mechanically efficient drilling provided an engineering basis for selecting WOB and was a major factor in the observed drilling performance increase.

In the planning phase this approach generates an engineered parameter roadmap tailored to each specific application and bit design, and provides WOB and torque targets as input for BHA design. Many other drilling parameter optimisation schemes require significant intervals of steady drilling to calibrate underlying models. Rapid changes in formation properties over the calibration interval could make the parameter recommendations inappropriate for the rock actually drilled. In contrast the method described in this paper uses real time, instantaneous performance measurements to determine whether the parameters are delivering mechanically efficient drilling. Its recommendations are consequently more robust against fluctuations in formation drilling properties, at least for the predominantly carbonate formations so far evaluated.