SPE/IADC Drilling Conference and Exhibition

Selective cementing is required in challenging wellbores with tight mud-weight windows between low-and high-pressure formations around the Arabian Gulf. It is typical to cover the Thamama 5,6 high-pressure formation and the Mishrif low-pressure formation in the Satah Al Razboot (SARB) field and the Salabikh formation in the Zakum and Umm Shaif fields in a single 12.25-in. hole section. This paper will discuss the reliability and cost impact of using new packoff stage-cementing equipment for cementing and zonal isolation in this situation.

Operators have a history of compromised casing integrity requiring intervention of wells because of the short lifetime of stage-cementing equipment. They have been forced to select other, more costly and more time-consuming methods (requiring four to six trips), such as installing a liner hanger and a tieback to surface. Although these methods are reliable and field proven, they have added considerable upfront investment in rig days and greater expense to the operation.

The evolution of reliable, gas-tight stage cementers (two-trip systems) rated at up to 10,000 psi at 350°F reduces the required number of operating days and total well costs and expands the technology limit for more challenging well conditions.

Rigorous testing and equipment qualification to International Organization for Standardization (ISO) 14998 V0 and ISO 14310 V0 have established confidence in stage-cementing tools with integral packer and slip systems. Based on this validation, wells in the Arabian Gulf Region can now be constructed using a single long string of casing, thereby eliminating the added expense of a liner hanger and liner tieback system. In addition to equipment savings, these stage-cementing tools reduce by as many as to 6 to 7 days the total number of operating days required to construct the well. The tools also reduce approximately US $1 to $1.5 million in direct cost and subsequent costs of intervention over the life of the asset.

This paper will provide insight into equipment installation methods and comparative time and cost for the use of pack-off, two-stage cementing tools in the United Arab Emirates. Technology innovation was achieved by combining completion accessories and downhole products that meet international standards set forth by ISO/API. This maximizes the reliability and validates the extended limitations of the technology to apply alternative well construction techniques that will retain wellbore integrity and reduce cost over the life of the well.

Substantial volumes of oil and gas reserves have been discovered in the Norwegian sector of the Barents Sea. This will give numerous field developments opportunities in the years to come. However, some of these oil reserves are located within thin reservoir beds which maybe as shallow as 200 to 250 m TVD below mudline, which results in development drilling challenges to economically develop these reserves. The case study discussed in this paper shows how the use of a modern top hole well design can help facilitate the economic development drilling of these reserves.

OMV (Norge) AS have drilled a set of exploration and appraisal wells in the production license PL 537 located about 350 km north of Hammerfest, Norway. The appraisal well "Wisting Central II" was planned as a horizontal well with three main objectives. The first objective being to prove that it is possible to penetrate such shallow reservoirs horizontally, the second one being the need for a representative production test from the reservoir and as last objective to gain appraisal information like oil water contact, reservoir data, etc. All well objectives were achieved according to plan.

This paper will present one of the key technologies that enabled the 1.4 km long horizontal reservoir section, at 250 m TVD below mud line, to be successfully drilled and tested. Typically in these wells the conductor would be set 50 to 60 m below mud line which would significantly reduce the probability to successfully build the hole angle up to horizontal at the desired reservoir entry point due to the limited TVD available.

Therefore, the plan was to substantially shorten the conductor, and to integrate it into a suction anchor based well foundation, a Conductor Anchor Node (CAN^®) in what is now known as a CAN-ductor design. This structure provided the required load capacity and allowed the conductor to be as short as 11 m below mudline. This allowed sufficient TVD for building hole angle and achieve the horizontal reservoir entry point at only 250 m TVD below mudline. Thereby, this well could be successfully drilled as planned, to become the shallowest horizontal well ever drilled from a floating drilling unit.

Since the installation of the CAN with integrated conductor is performed by a vessel ahead of rig arrival the technical benefits are further supported by an overall cost reduction as rig time is saved by not having to drill the conductor hole section and subsequently run and cement the conductor. Further cost savings are achieved due to the fact that no remedial and top up conductor cement jobs are required when using the CAN concept. To be noted is also that the wells P&A operations are simplified.

Brazing technology allows metallurgical joining of dissimilar materials using a filler material. In this paper brazing technology applied to casing connections is presented. The initial application was triggered by challenges with mechanical and pressure integrity after expansion of casing connections. Creating a strong bond between the pin and the box could resolve this. Brazing was selected because of the combination of ductility and high bond strength and the relatively fast process to create the bond. The brazing process or temperature-torque-time process (TTT) is performed using regular casing connections, a filler material deposited by flame spray and a flux. Two processes were developed, one for expandable (VM50) grade material and one for quenched and tempered grade material. For this a rig ready (CLASS 1 DIV 1) prototype brazing system was developed consisting of an induction coil as the heat source, an environmental chamber to shield the hot work, and a modified power tong to provide torque. The results of a series of brazing trials on 8-5/8″ and 9-5/8″ casing connections are presented. The brazed connections were subsequently capped end pressure tested, expanded (when applicable) and load cycled. It is concluded that both processes produced leak tight casing connectors before and after expansion (when applicable) as shown by full scale tests

Measurement of downhole dynamics while drilling has become commonplace. However, the use of sensors to measure downhole dynamics while coring has rarely been exploited. This paper will detail the use of compact dynamics sensors strategically placed within the coring assembly. A unique 4" (core diameter) jam mitigation system provides two jam protection, significantly improving core quality and reducing the total economics of obtaining whole core samples. At the occurrence of a core jam, two telescoping liners deploy within the aluminum inner barrel, allowing ability to mitigate the core jam(s) and continue with coring operations.

Compact downhole dynamics data recorders are strategically embedded in the core hanger (non-rotating) and near-bit stabilizer directly behind the core head (rotating). The data recorders are fitted with 3-axis inclinometers, 3-axis shock sensors, 3-axis gyros and two temperature sensors. Measurements include shock, vibration, rotation speed (angular velocity in RPM), torsional oscillation, stick-slip, gravity toolface, inclination and temperature.

The sensors have been deployed on multiple coring applications throughout North America land. The data recovered revealed formation related coring dynamics response while transitioning through interbedded intervals. Certain formations produced very high shock and vibration levels that could potentially cause damage to core quality and equipment. The onset of shock and vibration also revealed a significant temperature rise above bottom-hole temperature due to the coring dysfunctions.

This paper will detail the coring dynamics data captured from the sensors. The dynamic response of a coring assembly is significantly different from that of a drilling assembly due to the assembly mechanical dimensions and rock recovery methods. Proprietary software is utilized to merge downhole dynamic recorder data and surface Electronic Drilling Recorder (EDR) data. The software provides a fast and efficient interface to view the merged data, allowing surface and downhole correlation of the information.

An experimental set-up is established, designed for recording the absorption rate of a liquid during gas influx and at rotational flow conditions in an annulus. Likewise, the set-up is designed for monitoring the degassing rate from the liquid during controlled depressurisation, resembling the pressure drop during vertical annulus flow.

The set-up is designed for system conditions up to 400 bar, 150 °C, resembling downhole conditions. Annulus outer/inner diameters are 73/59 mm and the length of the main section is 1000 mm. A windowed section at the top allows monitoring of liquid volume changes and possible foaming behaviour during gas absorption/degassing. An inner cylinder can be rotated at speeds up to several hundred rpm, enough to produce Taylor-vortices and even turbulent flow in the annulus. For the reported test runs the system pressure is 100 bar, with temperatures 40 and 80 °C.

Two different base oils are tested, one normal mineral oil and one linear paraffin oil. A number of tests are run, with varying rotational speed and depressurisation rate. For tests with lower rotational speeds the degassing is postponed, with a corresponding higher maximum degassing rate as system pressure decreases towards atmospheric conditions. The impact from drill string rotation and type of base oil is shown, demonstrating the importance of describing the kinetics of the gas bubble nucleation rather than assuming instant equilibrium of gas and drilling fluid during the depressurisation during the vertical annulus flow.

Tests performed at experimental set-ups like the one presented will provide data for more advanced models of drilling fluid degassing behaviour. This will enable a more correct interpretation of data during well control events.

Rotary shouldered connections (RSCs) for polycrystalline diamond compact (PDC) drill bits have been unchanged since PDC bits were introduced in the late 1970s. These specifications were carried over from roller cone (RC) bits, which require significantly less torque to fail rock than a PDC bit. Current drilling processes and technologies highlight the need to re-evaluate connection requirements for PDC bits, specifically bits using the 3 1/2 REG connection. The Bakken shale requires extremely long laterals of up to two miles to remain within production zones, which are most economically drilled with a bent housing motor. These long laterals led to significant motor technology improvements for preventing stalls and allowing more weight on bit (WOB), increasing rate of penetration (ROP), and decreasing the number of bottomhole assemblies (BHAs), which reduced drilling costs. These advantages were achieved using a 5-in. motor that has a peak torque output greater than the makeup torque of the 3 1/2 REG connection. Therefore, it is necessary to re-evaluate PDC bit connections.

The connection fatigue index (CFI) is used to compare the fatigue life of connections given a set of parameters. It uses the Morrow strain-life equation to predict fatigue life. A unique feature of the equation is that it takes into account both stress and strain in the plastic region, which is crucial because the last engaged thread enters plastic deformation during makeup. The CFI includes Numbered Connections (NC) 35 and NC38 but does not include the 3 1/2 REG connection; therefore, the starting point for evaluation is to perform the calculations for the 3 1/2 REG connection. Fatigue life was evaluated using the CFI for the 3 1/2 REG, 3 1/2 REG with 1-in. stress-relief groove (SRG), NC35, and NC38 connections for a given bending moment.

Results from the Morrow strain-life equation predict that the NC35 with a SRG will have the greatest number of cycles to failure of the four connections evaluated. Based on the CFI calculations, the NC35 is predicted to last approximately 800 times longer than the 3 1/2 REG, 40 times longer than the NC38, and 10 times longer than a 3 1/2 REG with 1-in. SRG. The following thread form characteristics account for the exponential increase in life of the NC connections over the 3 1/2 REG: larger pitch diameter, SRG, larger root radius, and reduced taper angle. The NC35 connection was then field tested in a Bakken shale lateral.

As well plans are modified for shale drilling and motor technology advances, connection advances are also required. At a minimum, the makeup torque of the connection should be greater than the torsional output of the motor to prevent downhole makeup, mud seal galling, and reduced fatigue life.

Drilling of long horizontal wells is subjected to challenges, such as hole cleaning, drill string torque and drag, and challenges related to the Equivalent Circulating Density (ECD). Where the window for the downhole pressure is small, the length of the open hole section is limited by the dynamic ECD. The result is that several liners or casing strings may be required to reach the target depth.

The Reelwell Drilling Method provides a new solution for above mentioned challenges, incorporating a dual drill string, with a separate channel for the return fluid from the well. This arrangement enables Managed Gradient Drilling, i.e. to drill with a constant downhole pressure gradient that can be controlled to be nearly independent of the flow rate. The solution is similar to Managed Pressure Drilling, however, differs in that the downhole pressure gradient is managed instead of the pressure at one depth in the well. In addition, this new method of ECD control provides efficient hole cleaning at low flow rates, and enables torque and drag reduction due to buoyancy of the drill string.

A shallow horizontal trial well was drilled onshore Alberta, Canada, March 2016, to verify the new technology. New drilling equipment, including a newly designed aluminum dual drill string was used. New drilling procedures were employed, including the new Heavy Over Light drilling fluid solution. The equipment and procedures successfully verified the key benefits of the technology: –

Managed Gradient Drilling with ECD eliminated by near static well annulus fluid.

In the following sections, we describe the technology, how the field trial was organized and present drilling data from the shallow horizontal drilling operation that confirmed the capabilities of the system.

Increased use of Managed Pressure Drilling (MPD) has enabled a significant improvement in drilling operations through the ability to accurately control pressure within a narrow window and by actively managing the annular pressure profile. However, the technology has not yet reached its full potential; well control events involving a gas influx causes two-phase flow in the well and can lead to severe deterioration of pressure control performance. In this study, a robust model-based MPD control system is presented and results from drilling a well in the Umm al-Quwain region in the UAE demonstrate invaluable benefits for both normal operations and during well control events.

Due to its transient nature, drilling has always been a complicated operation and requires highly skilled personnel to achieve the desired pressure control accuracy. The introduction of automated MPD systems tries to implement more robust and safer control over well control operations that were previously manual tasks, however, this is still a challenge since wellbore conditions are constantly changing. This has prompted the need for proactive and model-based control techniques that act in advance to optimize the performance based on measurements and knowledge of the system. The development of this state-of-the-art MPD control system involved detailed validation in a high-fidelity simulator and thorough tests of robustness and performance in a full-scale flow loop with continuous gas injection capabilities, with focus on two-phase flow and gas influx handling.

Results from field operations show that the model-based MPD control system maintains robust performance during planned operations such as connections and drilling ahead. Based on pump flow measurements surface back-pressure or bottom hole pressure are maintained constant during fast pump ramp-down and ramp-up without the use of a back-pressure pump. Usually, MPD control systems require strict procedures on pump ramp speed to maintain constant pressure during transient operation. In this paper, the model-based control system implemented is shown to handle irregular pump flow changes and still maintain constant surface back-pressure or bottom hole pressure. In particular, a simulated pump emergency shutdown is shown where the pumps are stopped in less than 20 seconds. The MPD control system still managed to maintain constant bottom hole pressure by closing the chokes in a controlled manner.

In summary, this paper presents a field implementation of a fully model-based MPD control system that demonstrates its ability to compensate for irregular pump flow changes. Throughout these irregular pump flow changes, the control system maintains constant bottom hole pressure or surface back-pressure. Furthermore, the system demonstrates the ability to maintain the desired pressure control precision in all normal operations and during all unplanned events experienced during the operation.

This paper aims to provide an understanding of the various measurement-while-drilling (MWD) surveying enhancement techniques applied in drilling operations at the Goliat Field located in the Barents Sea to assure accurate wellbore positioning.

In high-latitude locations such as the Barents Sea, the elevated, time-dependent variations in the magnetic field create a challenge to the azimuthal measurements provided by the MWD tool. This will induce large uncertainty levels in the MWD surveys compromising the azimuthal errors established within the standard industry error models. To compensate for this effect, crustal magnetic field and time-based magnetic field disturbances were acquired to understand their impact on the MWD surveys and any associated error. This permitted drilling without compromising rig time, and the resultant reduction in lateral uncertainty was approximately 65%.

With regards to true vertical depth (TVD) optimization, the nature of the reservoir targets required tight TVD tolerances. To reduce the TVD uncertainty and maximize these targets, dual inclination analysis was performed while drilling. Control checks of the continuous and static inclination data from the MWD and rotary steerable system (RSS) reduced the sensor error term of the TVD error model definition and hence produced an improvement of up to 67%.

Seven wells have been drilled in the Goliat Field based on the methodology described in this article. In the planning phase, it was noticed that extra surveying techniques would be required to achieve the objectives for lateral and TVD placement. Survey management workflows were implemented to ensure consistency with regards to surveying accuracy.

Drilling and environmental challenges encountered in the Barents Sea push the boundaries of every aspect of current surveying techniques. Adherence to survey management procedures and understanding of the impact in the measurements generated by the disturbance in the magnetic field improved efficiency in the drilling operation and helped to achieve the critical well positioning objectives for this field.

Historically, everyday drilling dynamics measurements rely on the data captured at the Measurement-while-drilling (MWD) tools. These measurements only provide data at the location where the MWD placed in the bottom-hole assembly (BHA). Embedding low-cost sensors at the drill bit, bit box of steerable motor, and top sub of the steerable motor, the sensors provide data at point of insertion giving a much clearer understanding of downhole parameters. New 3-axis solid-state gyro sensors were added in the data recorder to measure accurate rotation speed, torsional oscillation and stick-slip at the bit, bit box and other parts of the BHA/drillstring. Proprietary software was used to merge the "at-point" downhole data with Electronic Drilling Recorder (EDR) data.

The data retrieved at the in-bit and bit-box drilling dynamics recorders, along with other points in the BHA, confirmed the effectiveness of "at-point" measurements for correlating bit conditions with downhole drilling dynamics. This granularity of the drilling dynamics data captured "at-point" is typically not seen from an MWD sensor. The in-bit and at-bit measurement revealed critical drilling dynamics functions that effected bit performance and life. Significant temperature increases at the bit were noted in certain formations where excessive dysfunctions were present.

This paper describes the results obtained from the "at-point" sensors while drilling in some of the harsher plays in North America land (NAL). Using proprietary software, the downhole data was merged with EDR data to show the relationship between surface and downhole. Since the bit is typically semi-decoupled from the drillstring (through the mud motor power section), the data gathered from the in-bit and bit-box sensors provide a new dimension of data for bit development.