The Offshore Operators Committee recognized major contributors to the SEMS Toolkit on 7 December. Front row from left are Brenda Kelly and Julia Swindle, IADC; Milton Bell, ExxonMobil; and Bill Walker, Cobalt International Energy. Back row from left are Troy Nugent, Baker Hughes; Greg Duncan, ConocoPhillips; and Jeff Ostmeyer, Anadarko.

ough an OOC task force and in cooperation with the Center for Offshore Safety (COS), the toolkit was developed to address consistency and compliance with new requirements by the US Bureau of Ocean Energy Management (BOEM), as well as their effective networking with other industry representatives.

IADC’s Dr Brenda Kelly, senior director of accreditation and certification, and Julia Swindle, industry compliance specialist, attended the ceremony to receive the awards from OOC chairperson Susan Hathcock, Anadarko Petroleum.

Dr Kelly’s contributions were her leadership of the Competence Subcommittee, development of the Knowledge and Skills Documentation Tool, contributions to the SEMS Compliance Readiness Worksheet and other tools, and speaking at a series of rollout conferences held in August and September last year. Ms Swindle contributed to review of all tools and provided administrative support of the entire SEMS Toolkit development effort. IADC has seconded Ms Swindle to work with the COS for one year to help with the initial establishment of the COS.

Besides Dr Kelly and Ms Swindle, other recipients of the award included Milton Bell, ExxonMobil; Greg Duncan, ConocoPhillips; Roger Molaison, BHP Billiton; Troy Nugent, Baker Hughes; Jeff Ostmeyer, Anadarko; Kim Parker, Hercules Offshore; Ruth Rodriguez, Delmar; and Bill Walker, Cobalt International Energy. Each recipient contributed significantly to the development of the tools in the toolkit, working with subcommittees and/or providing administrative support. A significant number of IADC member companies also contributed to the effort.

“The participants on the task force have my sincerest gratitude and respect for their leadership and contributions to the SEMS toolkit, which is of immeasurable value to our industry,” said Mr Ostmeyer, who led the toolkit development effort.

Currently, the OOC SEMS Subcommittee and its task groups have concluded their work with the public release of 8 SEMS Toolkit products. Tools developed were:

• Audit checklist;

• Contractor readiness tool;

• Matrix of regulatory required training for drilling, production and marine positions;

• SEMS orientation curriculum;

• Knowledge and skills documentation tool;

• Operator-contractor agree letter templates; and

• Definitions.

These tools are available on the IADC website.

The COS will adopt all tools and maintain them going forward, although a small team from the OOC SEMS Subcommittee continues to work with the COS in the development of the Auditor Certification Program.

 Joe Hurt (right), IADC regional vice president North America and lead staff land/HSE, presents Justin Hodges (left), director of safety, claims &  risk at Hodges Trucking, with the IADC Committee Chairman’s plaque for leading the Rig Moving Committee from 2010 through 2011. Mr Hodges’ successor is Anthony Zacniewski, director of HSE at Bandera Drilling.

Geer named IADC regional director – ME & Africa

Dave Geer has joined IADC as regional director for the Middle East & Africa, responsible for coordinating and promoting the IADC’s activities in those regions.

Mr Geer has more than 34 years of experience in the drilling industry, including 15-plus years working offshore in several positions and 19 years in management positions in sales, project management and marine operations.

He has expertise in MODU operations, risk management, safety and loss control, regulations and contracts.

By Pedro Martinez Aguilar, Repsol Exploration; Michael Arnold, John Lee, Boots & Coots, a Halliburton Service

Partial mud-loss in the Tournasian formation occurred because the formation permeability and porosity were sufficiently high to allow loss of whole mud. An open-hole formation integrity test (FIT) should be performed after repairing the loss zone and regaining circulation to ensure the wellbore pressure integrity is still equivalent to the FIT recorded at the last shoe depth.

The outcome of a well control and blowout incident reflects how well a crew is trained and prepared. This article will discuss the sequence of a well control operation that occurred in Algeria in December 2008, which includes the influx, steps to identify the situation, operations to control the underground blowout and the response of the well.

An operator drilled a 12 ^1/4-in. exploratory well at 11,516 ft in the Emsian formation and set a string of 13 ^3/8-in. casing at 5,250 ft. A pit gain was observed, and the well was shut in. The maximum annulus pressure recorded after shut-in was 570 psi. A sudden drop in annulus pressure to 325 psi suggested lost circulation and was assumed to be in the Tournasian formation (5,305 ft to 6,180 ft), where severe lost returns had been recorded while drilling (5,580 ft to 5,740 ft).

The pressure drop made it difficult to assess the kick, thus hindering conventional well-control techniques.

Initial Well-Control Actions

Pore-pressure equivalent mud weight (EMW) at the Emsian formation was estimated to be 11.7 to 12.7 lbm/gal. The formation-strength EMW at the Tournasian formation was estimated to be 10.0 to 11.7 lbm/gal. Believing the well was experiencing losses to the Tournasian, 189 bbl of 11.6-lbm/gal mud was pumped into the casing annulus. The annulus pressure remained constant, indicating the possibility of an underground blowout.

As the annulus pressure continued to increase to 1,000 psi, 340 bbl of 11.6-lbm/gal mud was pumped down the casing annulus to reduce the pressure. A volume of 340 bbl of 9.9-lbm/gal mud was pumped down the drill string while maintaining a maximum choke-back pressure of 1,600 psi. After pumping the mud, the stabilized pressure was used to determine the bottomhole pressure. While adjusting the choke, an influx entered the wellbore.

To prevent the annulus pressure from increasing beyond 1,000 psi, batches of 13.3-lbm/gal mud were pumped periodically into the annulus. The initial volumes of mud contained lost-circulation material (LCM) to help cure the losses.

The drill pipe was filled periodically to avoid gas migration up the drill string. Shut-in drill pressure remained at 0 psi. Losses in the annulus were reduced when the LCM reached the loss zone, and the shut-in drill pipe pressure gauge began indicating pressure.

Sandwich-Kill Attempt

The hole was displaced through both the drill pipe and the annulus, “sandwiching” the influx into the lost zone.

The Emsian formation pressure was predicted to be between 12.1 and 12.7 lbm/gal EMW, meaning a 15.9-lbm/gal kill mud would overbalance the Emsian formation by +/- 3.2 lbm/gal. A cement unit was used to pump 818 bbl of 11.6-lbm/gal mud down the casing annulus, and rig pumps were used to pump 1,006 bbl of 15.9-lbm/gal mud down the drill pipe.

The operation was partially successful because the annulus pressure was still 600 psi at the end of the procedure. However, it confirmed that the bottomhole pressure and the pressure at the loss zone were higher than predicted.

Casing pressure began to increase, and drill pipe pressure remained at 0 psi. Once the casing pressure reached 2,050 psi, the drill pipe pressure increased proportionally to the casing pressure.

Communication between the annulus and the drill string was demonstrated by bleeding off 300 psi on the casing, causing a 25-psi drill pipe-pressure decrease. To keep the casing pressure as low as possible, gas was bled from the casing annulus until fluid was observed at the surface. Thereafter, the casing pressure could not be further reduced.

Circulation-Kill Attempt

Heavy mud was pumped down the drill string to control bottomhole pressure and to circulate gas out of the well. Without an accurate value for the bottomhole pressure, the proposed kill-mud weight was 13.3 lbm/gal, based on the mud hydrostatic pressure and the shut-in casing pressure but neglecting the height of the gas in the annulus.

After pumping began, drill pipe pressure dropped to 0 psi. Consequently, the choke had to be adjusted without a reference value for drill pipe pressure. The choke position was kept constant, adjusted only when annulus pressure increased. Mud losses were difficult to quantify, and the well was shut in when the rig ran out of mud.

During the mud buildup, temperature and pressure logs were run to the depth of the downhole motor in the bottomhole assembly. These logs indicated the fluid level was around 4,216 ft and the pressure at 11,411 ft total depth was 4,630 psi.

The temperature log detected disturbance around 5,600 ft, which corresponded to the depth of the Tournasian formation. The log response was interpreted as fluid movement. The repeat section of the log corroborated the crossflow at the Tournasian formation at the same depth where losses were experienced in drilling.

Annulus-Pressure-Control Attempt

Because drill pipe pressure was 0 psi, there was no reference for operating the choke. It was decided to maintain constant annulus pressure or allow it to decrease. Four LCM pills were pumped. As the first pill reached the thief zone, the losses decreased to zero. Subsequently, the pit levels increased, indicating slight gains. The volume pumped and the time when the LCM reached the surface indicated the hole was in gauge.

Once the losses were reduced to a minimum, the pump rate was increased and the choke was opened slightly to counteract the vacuum effect on the drill pipe. However, the mud level in the drill pipe dropped continuously.

When the choke opened to ^1/16 in., casing pressure dropped more than expected. This jeopardized the control of the influx from the Emsian formation. The pumps were stopped, and after a few minutes, the drill pipe pressure began to increase. An influx of gas appeared to migrate inside the string, prompting the pipe to be displaced with 13.3-lbm/gal mud.

The well response indicated gas remained in the annulus, and the integrity of the Tournasian formation was still low. The kill operation resumed, and 239 bbl of 12.1-lbm/gal mud were pumped ahead of the 13.3-lbm/gal mud. The 12.1-lbm/gal mud did not reach the Tournasian formation. Consequently, the pressure in front of the weak zone at the Tournasian formation was minimized. At that point, more LCM pills were pumped.

While making repairs to the mud-gas separator, additional influxes entered the wellbore. When pumping restarted, pressure peaks suggested partial plugging of the ports in the circulation sub. As a precaution, no further LCM was pumped.

The drilling log reflects the sequence of events of an underground blowout and the well control operations that occurred in Algeria in December 2008.

Low-Choke Attempt

Changes in the annulus pressure after shutting in the well indicated that there was still a small amount of gas in the annulus or at least above the Tournasian formation. The “low-choke” method was used, attempting to control the influx from the kick zone at the bottom of the well while allowing the loss zone to deplete to a lower pressure. The basis was to hold the choke pressure equal to or slightly greater than the last recorded shut-in value while circulating as fast as safely possible. The mud density was designed to sufficiently overbalance the kick zone.

An 11.6-lbm/gal mud provided 50-psi hydrostatic pressure, in addition to annulus friction-pressure overbalance to the kick zone. The choke pressure was calculated using the casing pressure observed at the beginning of the operation, with an additional 200-psi safety factor added. The circulating rate used was as fast as the surface equipment would allow. Sixty-three bbl of 12.2-lbm/gal mud were pumped into the annulus.

An increase in drill pipe pressure suggested the presence of gas inside the pipe. The operation was stopped when bottoms-up volumes from the Tournasian and the Emsian formations were observed at the surface, and the crew prepared to reduce the annulus pressure. Operations resumed after the drill pipe was filled.

The well was monitored, and the casing pressure was bled off 100 psi to test communication between the annulus and the drill pipe. An unexpected 200-psi increase in drill pipe pressure occurred, indicating there were now two different pressure systems partially isolated by one or more packoffs in the annulus.

Once the bottoms-up volume from the Emsian formation reached surface, the choke was opened at separate intervals to bleed off 200 psi. Four intervals were needed to reduce the casing pressure to 500 psi. Because it was difficult to keep the casing pressure stable, it was decided to fully open the choke, allowing the casing pressure to rapidly bleed off to 0 psi. No returns were recorded at surface.

The pump rate was increased without result, except for a brief increase in pipe pressure, which suggested a restriction or packoff was present in the annulus. A total of 110 bbl of mud, along with 60 bbl of water, was pumped down the annulus to compensate for the fluid-level drop. The calculated fluid level was 1,371 ft.

Once pumping into the annulus stopped and the casing pressure dropped to 0 psi, the blowout preventer was opened to monitor the well. Because of the possibility of pipe plugging and annulus packoff, the pipe was worked. Five feet of pipe movement was gained, but rotation was impossible. The well was shut in with the annular preventer when mud overflowed at the bell nipple.

An attempt was made to establish circulation. Initially, the casing pressure rose very quickly to more than 3,000 psi. On the second attempt, the drill pipe pressure increased from 1,800 psi to 3,500 psi after pumping only 31 bbl of mud. With an entire drill pipe capacity of 187 bbl, this indicated the pipe was plugged. Further, the casing pressure did not reflect the pressure changes. It was concluded that one or more packoffs were present in the annulus.

An unsuccessful attempt was made to break the packoffs by pumping down the annulus. Subsequent efforts focused on bleeding off the annulus pressure and attempting to work the pipe to free the drill string, and a “lubricate and bleed” method was attempted. Large amounts of gas were recorded at surface, resulting in the annulus pressure dropping to 0 psi, and losses were also recorded. After filling up the hole with 13.3-lbm/gal mud and water, the well again began to flow. A 50-bbl mud cap using a 13.3-lbm/gal high-viscosity pill was pumped down the annulus but was unsuccessful in preventing gas from percolating to the surface.

When the annulus was bled off and the mud level was confirmed to be at surface, the pipe was worked. The drill string was torqued-up and continued to be worked. The string did not become free, moving 8 ft upward without releasing any torque.

The pipe was completely stuck, and circulation was impossible. The operator abandoned the drilled section of the well. The inside of the drill string was killed by isolating the inside diameter with cement or mechanical plugs. The drill string was perforated as deeply as possible to isolate the annulus using cement. A coiled-tubing unit was then used to cut the drill string, and the Tournasian formation was allowed to unload.

Lessons Learned

• The Tournasian partial mud-loss event occurred because the formation permeability and porosity were high to allow loss of whole mud (natural losses). This was evident by treating the losses with LCM. It is recommended that an open-hole formation integrity test (FIT) be performed after repairing the loss zone and regaining circulation. This helps ensure the wellbore pressure integrity is equivalent to the FIT recorded at the last shoe depth.

• If leak-off occurs before the equivalent shoe FIT is reached, wellbore maximum allowable surface pressure and kick tolerance should be recalculated at the loss-zone depth to accommodate the downgraded FIT.

• If creditable formation-pressure data is not available, the heaviest kill-mud weight possible should be used.

• Training in kick detection and BOP shut-in on all rigs is recommended.

The main lesson learned from this incident was the necessity for well-trained and experienced drilling crews and the importance of adequately sized mud-mixing and handling equipment.

The authors thank the management of Repsol Exploration and Boots & Coots for permission to present this paper.

This article is based on a presentation at the 2011 IADC Critical Issues Asia Pacific Conference & Exhibition, 23-24 November, Kuala Lumpur, Malaysia.

By J.E. Chirinos, J.R. Smith, D.A. Bourgoyne, Louisiana State University

Figure 1 shows the layout for experimental well LSU #2, where a gas kick was emulated by injecting gas in the 1 ¼-in. tubing until a desired pit gain was obtained. The well was used to evaluate two non-circulating kick responses and the pump startup procedure for kick circulation after a non-circulating response is applied. A computer simulation approach was also used to evaluate and confirm the applicability of these procedures.

According to IADC, managed pressure drilling (MPD) is defined as “an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore.” The technology uses different approaches to control and influence wellbore pressure. It is able to actively manipulate the wellbore pressure profile by controlling backpressure, drilling fluid proprieties and circulating friction; hence, a combination of tools is used to achieve MPD objectives to reduce nonproductive time (NPT) and mitigate drilling hazards.

MPD has been shown to be successful in wells where kicks, lost returns, ballooning, wellbore instability and/or differential sticking cause excessive NPT or inability to reach objectives using conventional drilling methods.

Although the main application of MPD has primarily been drilling in a narrow margin between pore pressure and fracture pressure, it’s increasingly realized that MPD can be applied anywhere where more precise control of wellbore pressure is an advantage. As a result, the industry has addressed a significant number of challenges by using MPD. Applications include: narrow drilling margin between pore pressure and fracture pressure, depleted formations, tight-gas sands, shallow gas hazards, wellbore stability problems, fractured carbonates, HPHT wells, H₂S wells, slim-hole coiled-tubing drilling and casing drilling.

This article focuses on one variation of MPD – constant bottomhole pressure (CBHP) – which uses a combination of equipment to manipulate annular frictional pressure losses and casing pressure to keep wellbore pressure at a selected depth relatively constant. Although the CBHP method of MPD has better control of wellbore pressure while drilling, well control events can still occur because of uncertainty related to pore pressure and fracture pressure, human error or equipment failure.

Table 1 (left) provides an example pump startup schedule for routine operations. It steadily increases the pump rate to keep BHP approximately constant. CP* = desired casing pressure for routine operations. Table 2 (right): The post-kick pump startup schedule for MPD kick circulation is based on a stabilized shut-in casing pressure (SICP) and the routine pump startup ΔP.

Several alternative well control procedures during the application of the CBHP method have been studied by industry-supported research to establish a basis for determining appropriate procedures. This research has defined two non-circulating responses as preferable among multiple alternative non-circulating responses. These two responses are described as a simple shut-in and as a MPD pump shutdown with a “choked flow check.” Both require a pump startup schedule to begin circulating out a kick. The goal of this article is to explain and document these procedures and to demonstrate by applying them in computer simulations and to gas kicks taken in a full-scale experimental well.

The CBHP method is the most common variation of MPD. During its application, annular pressure in the well is held constant or near constant at a selected depth. CBHP actively controls the surface pressure using a drilling choke to compensate for changes in frictional pressure losses (ΔPAF) during routine operations, such as making a connection.

An important characteristic of this method of MPD is the minimization of wellbore pressure variation to keep wellbore pressure within the drilling margin. Consequently, it allows drilling within a narrower window, or margin, between fracture and pore pressures than conventional drilling methods.

CBHP uses a collection of tools to control wellbore pressure during drilling operation. The minimum equipment required to apply CBHP are a rotating control device (RCD), a drilling choke manifold and, typically, a non-return valve. The RCD keeps annular space closed and diverts flow to the drilling choke; it is equipped with a rotating packer that rotates and holds pressure in the well during drilling operations.

The drilling choke manifold helps manipulate and control surface pressure while drilling; it can be controlled manually, semi-automatically or automatically. A non-return valve or float valve is installed in the bottomhole assembly; it allows only downward flow of drilling fluids, which is necessary if the well will be statically underbalanced.

Other optional tools can complement CBHP operation to improve wellbore pressure management, such as coriolis meters (flow meter), continuous circulating systems, downhole deployment valves, backpressure pumps, surface multiphase separators, pressure-while-drilling tools (PWD) and hydraulic flow modeling.

Pump Shutdown, Pump Startup Schedule

Many authors have discussed the method used to transition from dynamic to static state during CBHP. Medley, et al, and Rehm, et al, described a method to achieve CBHP objectives when rig pumps are shut down. It relies on a hydraulic model to estimate annular friction losses and equivalent circulating density (ECD) at different pump rates. Then, the ECD is manipulated by adjusting the casing pressure to keep wellbore pressure constant when the pump rate is reduced.

Wellbore pressure and ECD estimates are made with hydraulic models and can be validated with PWD tools. For example, to make a connection, the choke opening is reduced to increase casing pressure to the desired pressure, then the pump rate is reduced. Thus, surface pressure increases as the frictional pressure loss decreases by an equal amount. This process continues stepwise until the annulus surface pressure is at the maximum calculated value and the pumps are stopped.

The final annulus surface pressure should be equal to the frictional annulus pressure losses in the well, plus any surface backpressure held during normal operations.

Table 3 defines the pump startup and pump shutdown schedule for normal conditions, and Figure 2 illustrates application of the schedule in well LSU #2. BHP was kept essentially constant during pump startup and shutdown.

Initial Responses during Well Control Operation

A few studies have been done in the area of initial responses to well control events for the CBHP method of MPD. Das (2007) documented the first research from the university-industry consortium related to initial responses to a kick taken during the CBHP method. He compared three initial responses by using computer simulation: shutting in the well conventionally, increasing choke pressure while keeping the same pump rate, and increasing pump rate while keeping choke pressure constant. The most important conclusions from this research were: a) no single response was identified as the best, b) circulating responses may stop the influx faster than non-circulating responses, and c) the increased choke pressure response leads to a lower shoe pressure than shut-in, thus it reduces the risk of lost returns at the shoe.

In 2009, Guner studied the most appropriate initial response and kick circulation method for an unexpected reduction of bottomhole pressure created by a surface equipment failure or unintended ECD reduction. The conclusions explained that shut-in was the initial response that is applicable for all kick scenarios; however, increasing choke pressure would generally be the most effective response when it was practical. For both responses, Guner recommended kick circulation at the normal drilling circulation rate.

In 2009, Davoudi documented a comprehensive investigation of alternative initial responses to gas kicks taken during drilling operations with the CBHP method. He studied nine responses, five of them non-circulating and four circulating responses. They were compared based on the ability to stop formation flow, minimizing the risk of lost returns and additional kick influx, and the reduction of pressure imposed at surface and the casing shoe.

Davoudi performed more than 150 simulations and found that no single best initial response to all kicks could be identified. However, three initial responses were demonstrated to have a broad application to different kick scenarios: a rapid increase of casing pressure until flow out equals flow in, a simple shut-in, and an adaptation of the MPD pump shutdown schedule that allowed confirmation of low rate kicks using a choked flow check. In addition, he concluded that the best initial response depended on well conditions and the equipment being used.

Based on the consortium research, Davoudi, et al (2010) presented a proposed approach for selecting initial responses during well control events for the CBHP method. They explained that one criteria in selecting the initial kick reaction must be the equipment available onsite, specifically whether flow-out metering was being used.

In addition, according to this approach, the selection of the initial response should consider the certainty of the well control event. Each initial response has key factors that need be considered to ensure applicability and efficiency during the well control operations.

Figure 3: Actual shut-in pressures in LSU #2 were recorded, with the stabilized SICP interpreted at 510 psi. Table 4: A post-kick pump startup schedule for the experimental well was made based on the schedule for normal conditions.

Research Method

This article focuses on evaluating proposed procedures for the two non-circulating kick responses described by Davoudi in 2010 and on the pump startup procedure for kick circulation after a non-circulating response is applied. Two approaches were used to evaluate and confirm the applicability of these procedures: computer simulations and full-scale experiments.

Non-Circulating Responses

Simple Shut in

This response is widely known and accepted in conventional operations. However, according to work by Gunner in 2009, the simple shut-in procedure can be applied in MPD operation where accurate flow metering is not available or where equipment failure endangers the operation. This procedure can be summarized as:

1. Stop drilling, i.e., pick up off bottom and stop rotating.

2. Shut down the pumps as quickly as practical.

3. Close the drilling choke as quickly as practical.

4. Record shut-in casing pressure (SICP) versus time.

Figure 4: In this plot of actual and simulation results for a simple shut-in and pump startup after the kick, Number 1 represents the moment when the valve from the gas source was opened to LSU #2, and BHP increased by more than 500 psi. Number 2 shows pressure in the gas source is reduced as gas was injected into LSU #2.

MPD Pump Shutdown with Choked Flow Check and Shut-in

This method is based on the pump shutdown schedule for routine operations in CBHP. It can be used to check for flow when signals of a kick are not clear. The procedure can be outlined as:

1. Stop drilling, i.e., pick up off bottom and stop rotating.

2. Apply the regular pump shutdown schedule.

3. At the end of the schedule, attempt to hold the casing pressure constant for approximately two minutes by adjusting the drilling choke.

4. If it is necessary to bleed fluid from the well to maintain a constant casing pressure, shut in the well by closing the drilling choke and record SICP versus time.

5. If not (i.e., if the casing pressure does not increase above the final schedule pressure with the choke closed), resume drilling operations but continue monitoring for kick warning signs.

The application of these non-circulating responses is dependent on the RCD static pressure rating. If the expected shut-in casing pressure will exceed the RCD rating, close the annular preventer or pipe rams and open the choke line valve with the well control choke closed rather than closing the drilling choke.

Pump Startup Schedule after a Non-circulating Response to a Kick

Pump startup and pump shutdown procedures are routine MPD operations that are intended to keep wellbore pressure relatively constant during pump manipulations. When a non-circulating response is applied, a new pump startup schedule to start kick circulation is needed. This procedure should keep BHP relatively constant and above formation pressure.

The goal of this part of the research was to document and evaluate a simple method to start the kick circulation and keep bottomhole pressure constant after a non-circulating response. The method uses information available on the rig to define a pump startup schedule.

The proposed procedure is:

1. A routine pump startup schedule should already exist. Table 1 shows an example of a pump startup schedule with four steps of increasing pump rate, Q1 to Q4. As can be seen from the table, when the mud pumps are off, the casing pressure (CP) is equal to the annular friction pressure loss (ΔPAF) plus a desired casing pressure for routine operations (CP*). Notice that during the startup, CP is reduced by a constant pressure increment (ΔP) at each step until it is equal to the CP*.

This schedule keeps BHP approximately constant while the mud pump rate is increased. Note that a pump shutdown would use this same schedule beginning at Q4 and reducing the pump rate.

2. Once a potential kick has been recognized and the relevant non-circulating response applied, is recorded until a stabilized SICP can be interpreted.

3. Based on the stabilized SICP and the routine pump startup ΔP defined in step 1, a post-kick pump startup schedule is defined for the MPD kick circulation. Table 2 illustrates a post-kick pump startup schedule equivalent to the routine schedule in Table 1. CP0 is selected as equal to SICP plus a desired safety overbalance factor (ΔPOB). At each step in the schedule, the CP is reduced by the same ΔP, and the flow rate is increased to the same Q as defined for the routine pump startup.

4. Once the post kick pump startup schedule has been applied, the pump rate stabilized at Q4 and the choke pressure stabilized at CP0 Kick – 4ΔP, the drill pipe pressure should also stabilize. The kick is then circulated out, keeping drill pipe pressure constant at that value and the pump rate constant at Q4, equivalent to the driller’s method of well control.

Figure 5: In the method of MPD pump shutdown with choked flow check and shut-in, although the casing pressure time response did not match exactly between simulation and experiment, the trends and magnitude of response to choke manipulation are similar.

Well Scenarios for Evaluating Procedures

LSU #2 is a 5,884-ft deep vertical well with 9 ⁵/8-in. casing. Most of the full-scale results of this research were measured in and then compared with computer simulations of LSU #2. Two additional well geometries were used to perform simulations representative of other drilling environments suitable for MPD application: Well X is a 6-in. slim-hole directional well with a potential deep kick zone whereas Well Y is 12 ¼-in. straight hole with a potential high-pressure sand at the bottom.

Simulation Procedure

The computer simulations start during drilling operations just above the high-pressure sands in wells X and Y. For LSU well #2, a high-pressure sand was created in the simulator to emulate real conditions. The bit would drill into the high pressures, where a gas kick would be taken. Two initial responses were used to stop formation flow: simple shut-in and manual MPD pump shutdown with a choked flow check. If a simple shut-in response was used, the pumps were shut down, and then the choke was closed as fast as practical. However, if a manual MPD pump shutdown with choked flow check was performed, the pump shutdown schedule for routine operations was applied.

At the end of the schedule, the casing pressure that was required to compensate for the lost annular friction (ΔPAF) was held constant for approximately two minutes before shutting the well in, unless shutting in was required to maintain casing pressure. In both cases, SICP was recorded and used to create a pump startup schedule for kick circulation. All simulations were carried out until the gas was circulated completely out of the system; the data was recorded and analyzed using a spreadsheet.

Experimental Procedure

In the experimental well LSU #2, drilling fluid was circulated down the annulus between the 3 ½-in. and 1 ¼-in. tubing at the desired pump rate, and the flow returns were taken through 3 ½-in. by 9 ^5/8-in. annulus. The gas kick was emulated by injecting gas in the 1 ¼-in. tubing until the desired pit gain was obtained. Subsequently, the planned initial response was applied to stop formation flow and circulate out the kick. The influx was circulated out through a mud-gas separator, where the gas was directed to the flare and the drilling fluid was returned to the mud pits.

During the experiments, the drill pipe, casing and gas-injection pressures at the surface were continuously monitored and recorded, and subsequently analyzed.

Pump Startup, Shutdown for Routine Operations

The method described was tested in a full-scale experiment in the LSU #2 well. The drilling fluid used in the experiment was water, and the kick fluid was natural gas. A restricted valve was used in a surface return line to simulate higher annulus frictional pressure losses. Conventional detection for kicks was used in this experiment. The pump startup and pump shutdown schedule for normal conditions is detailed in Table 3, and Figure 2 shows its application. Solid lines represent data from the actual well, and dashed lines correspond with data for the equivalent computer simulation. Notice that BHP was kept essentially constant during pump startup and pump shutdown.

Simple Shut-in and Pump Startup after the Kick

The full-scale experiment was performed according to the procedure explained above. Gas was injected into the well until a 10-bbl kick was recognized. Then the well was shut in, and SICP was recorded vs time. The initial circulating underbalance was approximately 240 psi. Figure 3 shows shut-in drill pipe (a non-return valve was not used) and casing pressure buildup; the stabilized SICP was interpreted to be 510 psi.

Table 4 illustrates the post-kick pump startup schedule based on the pump startup for normal conditions in Table 3 and the SICP. In this experiment, ΔPOB was assumed to be equal to zero.

Once the post-kick pump startup schedule was prepared, it was applied manually by two persons: one operated the pump and the other manipulated the choke to control casing pressure. Figure 4 shows the experimental results.

It can be observed from the graph that BHP was kept almost constant during the post-kick pump startup, which achieves the goal described in previous section. Notice that the drill pipe and bottomhole pressure results from the experiment (solid lines) and the simulation (dash lines) are not identical for this case, probably because it was difficult to get exactly the same casing pressure versus time in the simulation as in reality.

However, the similarity in behavior supports the relevance of using simulations for this study. In the plot, number 1 represents the moment when the valve from the gas source (a well that is essentially a gas storage bottle) was opened to the LSU #2 well; notice that BHP increased more than 500 psi. Number 2 in the plot shows how the pressure in the gas-storage well is reduced as the gas is injected into the LSU #2 well to simulate the gas kick. BHP was controlled when the shut-in procedure was applied.

MPD Pump ShutDown with Choked Flow Check, Shut-in

The second non-circulating response was applied to a low feed-in rate kick. The gas-storage well pressure was set to cause a 100-psi underbalance in LSU #2. A restricted flow path from the storage well was opened, a slight increase in return flow was detected as an indication of a possible kick, and the manual MPD pump shutdown with choked flow check was applied.

Figure 5 shows the experimental results. It can be seen that the pump shutdown schedule described in Table 3 was applied to keep BHP constant. The choked flow check was extended over a period of about five minutes to show that the choke had to be opened periodically to maintain the intended casing pressure at the end of the MPD shutdown schedule.

When the choke was subsequently closed, the casing pressure would build back up, indicating that the well had been underbalanced. The experimental results from the test well were also compared with a computer simulation for the same conditions, shown in the dashed lines. Although the time response of casing pressure in the simulation is not an exact match to experiment, both the trends and the magnitude of the response to choke manipulation are similar.

A pump startup schedule (Table 5) was defined for Well X to keep BHP constant during pump manipulations; the schedule is simulated in Figure 6.

Example Simulations of Shut-in and Pump Startup

Simulations were conducted to provide a basis for evaluating the application of pump startup schedules to a wide range of well conditions. This section describes an example of these simulations.

A pump startup schedule was defined to keep BHP constant during pump manipulations (Table 5) for Well X. Figure 6 shows the simulation of the pump startup and pump shutdown for routine operations for the well. It can be seen that BHP is kept almost constant while the pump is being started and shut down.

Notice that casing pressure is used to compensate the loss of friction in the well; it is increased when pump rate is reduced, and it is reduced when pump rate is increased.

Once the pump startup schedule for routine operations was defined, the kick simulation was run according to the procedure described in an earlier section. The well was drilled into a high-pressure sand with a circulating underbalance of 0.2 ppg. As a result, a 20-bbl kick was taken, the well was shut in, and SICP was recorded.

Based on the pump startup schedule for routine operations (Table 5) and the SICP, a new pump startup schedule (Table 6) for kick circulation was built, and the kick was circulated out successfully. The stabilized SICP was equal to 1,183 psi. A safety overbalance (ΔPOB) of 100 psi was added to the SICP for determining the post-kick startup schedule.

Figure 7 shows the simulation results for this scenario. A kick was recognized by the increase of surface mud flow rate out (Q_out) and pit gain, as shown by the red line and the green line respectively. Drilling was stopped, the mud pump was shut down, and the choke was closed with a pit gain of about 20 bbls. Casing pressure subsequently increased to balance the kick zone’s pressure at SICP = 1,183 psi. Hence, the BHP increased and stopped formation flow.

At this point, the post-kick pump startup schedule was prepared and applied. Figure 6 demonstrates how casing pressure (purple line) was decreased while pump rate (blue line) was increased according to the schedule in Table 6. Notice that BHP (light blue line) was kept almost constant during the application of this schedule.

Three well scenarios, LSU #2, Well X and Well Y, representing hole sizes from 6 in. to 12.25 in. were simulated. Kicks were simulated in each well configuration for total pit gains of 2, 10 and 20 bbl and for three levels of circulating underbalance. All simulations were run successfully and demonstrated that BHP was kept relatively constant using the proposed post-kick pump startup schedule and procedure.

Table 6: A pump startup schedule for kick circulation in Well X was built. Figure 7 shows the simulation results of shut-in and pump startup for Well X.

Conclusions

• Simple shut-in is a procedure that can be applied during MPD operations to stop formation flow. Previous work has shown that it is the preferred response to a kick if accurate flow-out metering is not available or if a circulating response is impractical due to an equipment failure. Simple shut-in can be applied rapidly, typically in less than one minute, and it can provide a SICP as a basis for a pump startup schedule.

• The MPD pump shutdown with choked flow check response allows checking for flow during MPD operations without letting bottomhole pressure drop significantly below the intended pressure. Consequently, this response can be used to detect or confirm, and then shut in, low feed-in rate kicks that cannot be detected conclusively during circulation.

• The pump startup schedule method described successfully maintains bottomhole pressure relatively constant during pump startups for kick circulation. It is applicable after all non-circulating responses.

• Applicability of these methods was confirmed with both full-scale experiments and simulations covering a wide range of well conditions.

By Srinivasa Koneti, Samit Gokhale, Thomas Wadsworth, T.H. Hill Associates

Figure 1 (left): Intergranular cracking, characterized by triple points, rock-candy or a faceted appearance, occurs at and along the grain boundaries of metal. Figure 2 (right): Transgranular cracking occurs through or across the crystals or metal grains and is characterized by cleavage steps, river patterns, feather markings and tongues. This shows an example of a transgranular fracture on the fracture surface of low-carbon steels.

Brittle fracture of oilfield tubular components can occur due to the material having low fracture toughness – such material often presents low Charpy V-notch (CVN) impact energy values – or from exposure of the material under load to certain corrosive operating environments. A brittle fracture can show characteristics of transgranular or intergranular cracking when analyzed through a scanning electron microscope (SEM).

Intergranular cracking is the cracking or fracture that occurs at and along the grain boundaries of a metal. It is characterized by triple points, rock-candy or a faceted appearance when the fracture is analyzed through SEM. Figure 1 shows a typical example of an intergranular fracture on the fracture surface of low carbon steels.

Transgranular cracking is the cracking or fracture that occurs through or across the crystals or metal grains. It is characterized by cleavage steps, river patterns, feather markings and tongues when the fracture is analyzed through a SEM. Figure 2 shows a typical example of a transgranular fracture on the fracture surface of low-carbon steels.

Intergranular cracking is often the mode of fracture that occurs when tubular components are exposed to environmental conditions that contain aqueous H₂S. Such failures promulgate the notion that detection of intergranular cracking morphology on fracture surfaces is confirmation of failure through sulfide stress cracking (SSC) or hydrogen embrittlement, even when no evidence exists for exposure to H₂S or a source of nascent hydrogen.

Study of intergranular cracking related failures has shown that such failures can occur not only when the component is exposed to nascent hydrogen but can also be caused by temper embrittlement of the material resulting from improper heat treatment.

Temper embrittlement typically occurs when carbon or low-alloy steels are held at or slowly cooled through the temperature range of 375°C (705°F) to 575°C (1,065°F) during the tempering process. If the steels are tempered or slowly cooled at these temperatures, the material shows brittle characteristics (loss of impact toughness).

Steels that have experienced temper embrittlement can be restored to their original or expected toughness by heating (tempering) to 600°C (1,100°F) or above, followed by rapid cooling to below approximately 300°C (570°F).The fracture surface of a material with low CVN impact energy values (brittle material) would normally show transgranular signatures when analyzed under a SEM, whereas a ductile material affected by environmental attack, such as hydrogen embrittlement, shows intergranular separation at grain boundaries.

However, brittle fracture of a material that undergoes temper embrittlement also shows signs of intergranular cracking. Examination of the fracture surface of a component that has undergone temper embrittlement can present intergranular or mixed mode of intergranular and transgranular fracture morphology.

n Case 1 from South Texas, the pin connection of a new saver sub failed. The drilling engineer recognized the failure as a brittle failure.

Case studies of Temper Embrittlement Failure

Case 1 – South Texas, onshore US

In March 2009, while making up the pin connection (6 ^5/8-in. reg) of a saver sub, the pin connection on the sub failed. The operator reported that the saver sub was procured new and was in service for three days before the failure occurred.

Based on the appearance of the fracture surface, the proximate cause of the failure was readily recognized by the drilling engineer as a brittle failure. To confirm the failure mechanism, the failed sub was sent for failure investigation.

In Case 2 from Oklahoma, the pin connection twisted off while making up the pin connection of a saver sub.

Case 2 – East Oklahoma, onshore US

In May 2010, while making up the pin connection (6 ^5/8-in. reg) of a saver

sub, the pin connection twisted off. Based on the fracture surface morphology, the failure mechanism was identified as a brittle fracture with rapid crack propagation. To confirm the cause of the failure, the failed sub was sent for further investigation.

Case 3 – Northeast Trinidad, offshore

In April 2010, the operator was in the final stage of drilling a horizontal well that entailed the pullback of the 36-in. production pipeline. While pulling back drill pipe joint No. 90, a 7 ^5/8-in. reg pin connection on a sub that fastened the 42-in. hole-opener to the 500-ton swivel failed downhole.

In Case 3 from Northeast Trinidad (lower left), a pin connection on a sub that fastened the hole-opener to the swivel failed downhole.

The attached fractured sub was pulled out, and the mating portion of the sub was not recovered by fishing and subsequently resulted in losing the well. Based on the appearance of the fracture surface, the proximate cause of the failure was identified as fatigue, followed by a brittle fracture. To confirm the failure mechanism, the failed sub was sent for investigation.

Metallurgical analysis of the fractured pin connections on the subs was performed to identify the cause of the failure and the factors that contributed to the failure. To differentiate the fractured pin connections of the subs, the subs will be referred to as:

C1: Sub from Case 1

C2: Sub from Case 2

C3: Sub from Case 3

The fractures of all the pin connections were located in the last engaged threads of the pin connections. The last engaged threads of a connection experiences higher stresses and stress concentrations compared with the rest of the connection, making these threads susceptible to cracking. The as-received condition of the failed subs is presented in Figure 3. The C3 sub was received after initial metallurgical testing was performed by another lab. A portion of the sample that was used for previous testing was missing.

Figure 4: The fracture on the Case 1 sub showed a grainy texture and “chevron marks” that point toward the initiation site, which is typical morphology for brittle cracking.

The overall appearance of the fracture surfaces on the subs was flat and oriented perpendicular to the sub axis. The fracture on C1 and C2 exhibited a grainy texture and “chevron marks” that point toward the initiation site. This is typical morphology for brittle cracking (Figure 4).

The fracture on C3 exhibited a small fatigue region (approximately 5%) that was followed by brittle fracture. The fracture surface also had the grainy appearance (Figure 5). All three fracture surfaces present a minuscule shear lip, which is also typical of a brittle fracture. Note that the missing material was used for testing during previous investigation.

A thread profile analysis of the failed pin connections of C1 and C2 was performed to check for stretched threads, but no signs of such were observed. This gave further evidence that the pin connections on C1 and C2 failed in a brittle manner and not through ductile torsional/tensile overload.

Figure 5: The fracture on C3 exhibited a small fatigue region that was followed by brittle fracture. The fracture surface had a grainy appearance and presented a minuscule shear lip, which is also typical of a brittle fracture.

Material Testing

Material testing of the failed subs was performed to verify compliance with API Specification 7-1 and Standard DS-1 and to determine if improper material properties contributed to the failures. Tensile tests, chemical analysis and CVN tests were performed on the failed pin connection material of the subs.

Tensile strength and yield strength met the minimum requirements specified in API Specification 7-1 and Standard DS-1 for sub material. However, the CVN impact energy values did not meet the minimum requirements specified.

Typically, for the type of chemistry used, CVN values correlate well with fracture toughness. Low fracture toughness makes the material notch sensitive and typically results in predominately brittle fracture.

This indicates that the heat treatment processes were not performed properly to achieve the correct mechanical properties on the subs.

With temper embrittlement, generally, there is no detectable drop in expected yield strength, tensile strength and percent elongation of the material. A drop in the CVN values is often experienced.

In cases of extreme embrittlement, there may be a drop in the percent reduction of area. The material test results obtained on the failed subs are similar to test results commonly observed on components that have experienced temper embrittlement.

Because there is no major change in the tensile properties of the material, hardness testing cannot be used to detect temper embrittlement. Performing CVN tests followed by examination of the fracture surface of the CVN samples under a SEM are necessary to ascertain failure through temper embrittlement.

Figure 6: No signs of stretched threads were observed after a thread profile analysis of the failed pin connections of C1 and C2 was performed.

Scanning Electron Microscopy Analysis

The fracture surfaces of the failed pin connections on C1, C2 and C3 were electrolytically cleaned to remove oxides, which mask the fracture signatures. The cleaned fracture surfaces were then observed through a SEM. The fracture examination on C1 and C2 revealed features typical of transgranular fracture. The examination also revealed signatures of intergranular cracking (Figure 7).

The presence of both intergranular and transgranular features indicates a mixed mode fracture morphology. As discussed, the presence of intergranular cracking is often considered proof of failure induced through environmentally assisted cracking, such as SSC or hydrogen embrittlement. However, a saver sub is unlikely to come into contact with downhole corrosive environment.

Moreover, review of the operating conditions and environment provided no evidence of a source of nascent hydrogen. In this instance, presence of a mixed mode of intergranular and transgranular morphology on the fracture surface, combined with the low CVN values, indicates that the failure is more likely associated with temper embrittlement of the material resulting from improper heat treatment of the component.

Figure 7: The fracture examination using a SEM on C1 and C2 revealed features typical of transgranular fracture (left and middle) and signatures of intergranular cracking (left and right). The presence of both intergranular and transgranular features indicates a mixed-mode fracture morphology.

SEM analysis of C3 was also performed. However, no signatures were observed as the fracture surface was too corroded for examination.

To confirm if the subs underwent temper embrittlement, the fracture surface of the CVN impact test samples were analyzed under a SEM. Typically, examination of the fracture surface of CVN samples from a ductile material can present portions of ductile dimples and transgranular “cleavage” cracking.

This morphology is also expected on CVN samples that are machined from an inherently brittle material or a ductile material that has fractured through SSC or hydrogen embrittlement. The fracture examination of the CVN samples from the failed subs revealed mixed mode of intergranular, transgranular and some ductile dimple features (Figure 8).

This mixed mode of intergranular and transgranular cracking indicates that the subs likely underwent temper embrittlement resulting from improper heat treatment. Hence, presence of intergranular cracking does not confirm environmental cracking. Instead, CVN testing should be performed to check the fracture toughness of the material.

Additionally, the fracture surface of the CVN samples should be analyzed under a SEM to verify the fracture mode. Temper embrittlement of material is a strong possibility if the material presents low CVN values along with presence of intergranular or mixed mode of intergranular and transgranular cracking signatures on the fracture surface of the CVN sample.

Figure 8: The fracture examination of the CVN samples from the failed subs C1 (left), C2 (middle) and C3 (right) revealed mixed mode of intergranular, transgranular and some ductile dimple features. This indicates the subs likely underwent temper embrittlement resulting from improper heat treatment.

Guidelines on Alloying Elements

Temper embrittlement is often associated with the concentration of certain trace alloying elements, such as arsenic, antimony, tin and especially phosphorus. These minor impurities segregate along the austenitic grain boundaries during the tempering process and cause cracking along the grain boundaries.

Molybdenum, tungsten and zirconium greatly reduce embrittlement, and nickel, titanium and vanadium slightly reduce the temper embrittlement effects.

API Specification 7-1 and Standard DS-1 do not have any requirements for chemistry on subs. However, API Specification 5DP and Standard DS-1 have chemistry requirements for drill pipe tube and tool joints for phosphorus (0.020% max) and sulfur (0.015% max).

The sulfur content obtained on all the three failures was above the maximum allowed for drill pipe tube. The phosphorus obtained on C3 was above the maximum requirement, while the content for C1 and C2 was near the maximum allowed. This provides basis for strict control on these elements to minimize the possibility of temper embrittlement problems.

If not already required in the governing standard, supplementary requirements on content of phosphorus (0.02% max) and sulfur (0.015% max) should be specified when tubular components are ordered.

To check if the failure mechanism of the failed sub C1 was temper embrittlement, the sub material was re-heat treated. The re-heat treatment was also performed to confirm whether the sub was improperly heat-treated at the mill.

Sections of the failed pin connection were re-heat treated with the following conditions:

Condition 1: Temper at 657°C (1,215°F) for 45 min, and cool.

Condition 2: Austenitize at 872°C  (1,602°F) for 55 min; water quench; temper at 1,215°F (657°C) for 45 min; and cool.

The heat treatment procedures listed in the material test report (MTR) were used for re-heat treatment of the sub material. These conditions were chosen because the tempering temperature listed in the MTR does not fall in the temper embrittlement range.

If the sub was heat-treated at the mill with the conditions indicated in the MTR, temper embrittlement likely would not have occurred. After re-heat treating the sections from the failed pin connection with the conditions listed above, CVN impact tests were performed.

Significant improvement in the CVN values was observed from the re-heat treated material under both conditions. The reason for higher CVN values obtained through Condition 1 compared with Condition 2 is that the Condition 1 material underwent a double tempering process at the mill, and again during the re-heat treatment process.

The minimum and average impact energy of the re-heat treated sections was greater than the minimum required value specified in API Specification 7-1 and Standard DS-1. This confirmed that the failed sub was not heat-treated to the parameters listed in the MTRs.

Figure 9: To check if temper embrittlement still existed after re-heat treatment, the fracture surfaces of the CVN samples were analyzed under a SEM. Microvoid coalescence, seen as ductile dimples, was observed, which is indicative of ductile overload of the material.

To check if temper embrittlement still existed, the fracture surfaces of the re-heat treated CVN samples were analyzed under a SEM. Figure 9 present the fracture surfaces of the re-heat treated CVN samples as seen under SEM.

Microvoid coalescence (seen as ductile dimples) was observed on the fracture surface of the CVN sample, which is indicative of ductile overload of the material. No features of intergranular or mixed mode of intergranular and transgranular cracking were observed.

Hence, temper embrittlement was eliminated by performing the re-heat treatment on the failed sub material. Temper embrittlement was eliminated with only tempering the sub material (Condition 1). This confirms that temper embrittlement can be reversed with a tempering process performed at the appropriate temperature.

1. Detection of intergranular cracking morphology on fracture surfaces of a failed component is often considered to be confirmation of failure through SSC or hydrogen embrittlement, even when no evidence exists for exposure to H₂S or a source of nascent hydrogen.

Study of intergranular cracking related failures has shown that intergranular fractures can occur not only when the component is exposed to corrosive environment, such as aqueous H₂S, but can also be caused by temper embrittlement of the material resulting from improper heat treatment.

2. Temper embrittlement typically occurs when carbon or low-alloy steels are held at or slowly cooled through the temperature range of 375°C (705°F) to 575°C (1,065°F) during the tempering process.

3. Temper embrittlement is often associated with the concentration of certain trace alloying elements, such as arsenic, antimony, tin and especially phosphorus. These minor impurities segregate along the austenitic grain boundaries during the tempering process and cause cracking along the grain boundaries. If not already required in the governing standard, supplementary requirements on content of phosphorus (0.02% max) and sulfur (0.015% max) should be specified when tubular components are ordered.

4. The fracture surface of a failed component that has experienced temper embrittlement can present intergranular or mixed mode of intergranular and transgranular fracture morphology when analyzed under a SEM.

5. Generally, temper embrittlement of a material, does not lead to a detectable drop in expected yield strength, tensile strength and percent elongation of the material. However, a drop in the CVN impact energy values is often experienced, and in cases of extreme embrittlement, there may be a drop in the percent reduction of area.

6. Since there is no major change in the tensile properties of the material, hardness testing cannot be used to detect temper embrittlement of a material. Performing CVN tests followed by examination of the fracture surface of the CVN sample under a SEM are necessary to ascertain failure through temper embrittlement.

7. If the fracture surface on the failed components presents signatures of intergranular fracture, then it should not be presumed that the failure is associated with environmental cracking like SSC. Instead, CVN testing should be performed to check if the material has low impact energy values.

Once tested, SEM analysis of the fracture surface of the CVN sample must be performed to check for intergranular or mixed mode of intergranular and transgranular cracking. Presence of intergranular or a mixed mode of intergranular and transgranular morphology on the fracture surface of the CVN samples, combined with low CVN values, indicates a failure more likely associated with temper embrittlement of the material.

8. If the component being tested, such as tubing, does not have sufficient thickness to machine minimum required size CVN samples according to the governing API specification (minimum size accepted by API is 10 mm x 5 mm), then CVN samples should be machined to 10 mm x 2.5 mm (¼-in.) size to perform CVN testing.

Although the values obtained through testing cannot be compared against API specification requirements, the fracture surface of the CVN samples can still be analyzed under a SEM to check for intergranular or mixed mode of intergranular and transgranular cracking.

9. Temper embrittlement is a reversible process. Carbon and low-alloy steels that have experienced temper embrittlement can be restored to their original (or expected) toughness by heating (tempering) to 600°C (1,100°F) or above, followed by rapid cooling to below approximately 300°C (570°F). Material susceptibility to temper embrittlement can also be reduced by strict control and reduction of embrittling impurities, such as phosphorus.

Rotary steerables suit narrow formations; mud motors may be more cost-effective in broader boundaries

By Eric Malcore, Weatherford International Ltd

The ratio of directionally drilled wells to vertically placed wells is increasing. Access to progressively harder to reach reserves is driving more complex well geometries, which predicate the use of rotary steerable systems (RSS) to enhance rate of penetration (ROP), improve borehole quality and reduce torque and drag and stick slip. The various RSS technologies available today have revolutionized the drilling process in horizontal and deviated wells by facilitating greater intermediate reaches and longer laterals, allowing casing to be run more easily and allow proper weight transfer.

The service industry estimates that RSS technologies account for approximately $3.5 billion of the estimated $15 billion directional drilling market. The dynamics are shifting in favor of RSS.

Although not a new technology, high-performance mud motors also have become an accepted and reliable method in directional drilling operations, in many cases providing a cost-effective alternative to more costly rotary steerable tools.

Knowing when to choose a rotary steerable system and when to use a high-performance mud motor is critically important to optimize the drilling project from both an engineering performance and a cost perspective.

Many horizontal or deviated wells are extremely difficult or impossible to drill without an RSS. A key benefit of RSS technology is that it directs well trajectory without sliding, a condition that impacts the stability and orientation of the drill string to rotate in one direction. Without proper rotation, the entire drill string can stick to the borehole wall, making it difficult to achieve the desired weight transfer to the bit to achieve planned penetration rates. RSS tools provide continuous rotation of the drill pipe, minimizing the risk of the pipe becoming stuck or buckling.

Sliding also creates more waste because the lack of rotation keeps the fluid in a static state, making it more difficult to remove cuttings. The cuttings then pack off around the bottomhole assembly, causing the drill string to stick. With the continuous rotation enabled by rotary steerable tools, however, the friction holds the cuttings in suspension, allowing the fluid to create a vortex around the drill string to provide consistent hole-cleaning.

RSS technology also reduces drag, allowing extension in well reach, especially important in horizontal applications. Rotary steerables typically deliver a smooth in-gauge wellbore and control the toolface at the bit, which provides more accurate directional control and less tortuosity. They also enable the use of logging-while-drilling (LWD) azimuthal sensors to obtain full borehole images.

An important factor in rotary steerable systems is that they provide precise directional control and are therefore suited to narrow zones as tight as 1 ½ ft. In that regard, the tools also can provide geosteering in these narrow reservoirs, where corrections can be made in real time without sliding.

An RSS was used to successfully drill and complete a section of a horizontal water-injection well with an 8 ½-in. hole in Abu Dhabi.

Using Weatherford’s Revolution rotary steerable system, the operator was able to drill 2,200 ft (671 meters) at a depth of 8,725 to 12,918 ft (2,659 to 3,937 meters) in less than 90 hrs in one run, saving 41 hrs of drilling time and achieving a significant cost savings without nonproductive time.

The same system was used in another Abu Dhabi water-injection well to facilitate drilling and completion of an ultra-narrow, 6-ft zone with a 6-in. hole size and a run length of 4,193 ft (1,278 meters).

The operator was able to drill almost 20 ft (6 meters) deeper than anticipated, reaching a target that otherwise would have been missed.

In an onshore Saudi Arabian field prone to lost circulation, differential sticking and hydrogen-sulfide challenges, the same technology drilled a 3°/100-ft (30-meter) dogleg section with a 6 ^1/8-in. hole in an extended-reach horizontal water-injection well to a target depth of 16,856 ft (5,138 meters). Average ROP was 35 ft/hr (11 meters/hr). Prior to deployment of the system, optimal ROP had been difficult to achieve with a steerable motor assembly.

The system drilled a total of 7,316 ft (2,230 meters) in one run, achieving a field run-length record and meeting the operator’s goal to minimize excess tripping time. The operation saved 24 hours in drilling time and associated costs and allowed the operator to avoid stuck-pipe and lost-in-hole risks that occur in similar extended-reach wells.

In the Bay of Bengal in Eastern India, the same RSS technology performed a record-breaking shoe-to-shoe run in a claystone formation, with interbedded sandstone, marl and calcareous clay. The deep exploratory well had an inclination of 34°. The system drilled a 12 ¼-in. in-gauge hole and then drilled to a measured depth of 4,918 ft (1,499 meters) to improve the average ROP and reduce the number of wiper trips and backreaming. Drilling time was 192 hrs, with an average ROP of 25.6 ft/hr (7.8 meters/hr).

RSS technology has been enhanced in recent years by the development of motorized rotary steerable systems, where a power section placed on the RSS tool provides additional rpm and torque while still achieving the benefits of control and eliminated sliding. This hybrid-type application is increasingly being used in regions such as the Middle East, where the rock and carbonates are especially hard.

High-performance mud motors can save 50% or more a day over rotary steerable systems. Mud motors also can be used with smaller rigs that can’t rotate fast enough to enable the rotary steerable mechanism to perform. However, rotary steerables provide greater precision in directional control, an advantage in tight formations.

High-performance Alternative

Despite its many benefits, rotary steerable technologies can present some disadvantages, including cost, if used in situations where precise directional control is not the primary objective. For example, to justify the expense of using a rotary steerable system, the savings in rig time and other costs must be greater than the rotary steerable cost.

Rotary steerable drilling performance is delivered from the use of surface rotation, making them rig-dependent. They offer limited selection of bit sizes and speeds, and they involve greater complexities, both mechanically and electronically compared with motors. The high rotation speeds can cause premature wear to the casing and drill string, which can be slightly decoupled by using an integrated power section with the RSS, albeit adding significantly to the cost.

The replacement cost of a rotary steerable system, if it is lost in the hole, can exceed $1 million, depending on the system and size. That does not include the replacement cost of the accessory tools.

In cases where deploying an RSS is either cost-prohibitive or impractical, a high-performance mud motor can also achieve desired results, provided it is used in the proper application. However, high-performance mud motors are best suited to broad target areas and zones that require less precision, or in doglegs that are too aggressive for an RSS.

Used since the early 1990s for a multitude of oilfield applications, high-performance mud motors achieve greater torque and ROP than conventional mud motors. The mud motor leverages the reduced rubber profile in the power section to gain additional torque, which creates less deformation as the rotor spins. The reduced rubber deformation translates into more torque for the bit, which in turn allows for higher ROP and more aggressive bit designs.

For operators, the key advantage is that a high-performance mud motor can result in daily cost savings of 50% or more over an RSS. Lost-in-hole costs also are significantly lower; a 6 ¾-in. high-performance mud motor has a typical lost-in-hole cost of $168,000.

High-performance mud motors can often out-perform standard, non-motorized RSS, which depend on the rig rotary table to spin the bit. The motor power component of the high-performance mud motor, on the other hand, provides bit rotation and power directly to the bit. High-performance mud motors also can be used in situations that involve smaller rigs that can’t rotate fast enough to enable the rotary steerable mechanism to perform.

Another benefit is that all bit types and sizes can be used with a high-performance mud motor, making it useful for a variety of applications, including situations where a particular bit that is not compatible with an RSS must be run.

High-performance mud motors do, however, require sliding for directional control, which typically reduces ROP. They offer poor and inconsistent hole-cleaning and poor hole gauge. Also, LWD sensors often get pushed back farther from the bit. Motor bend with high-performance mud motors can limit the drill string rotary speed or not allow any rotation at all. These factors must be considered in selecting this method of drilling.

It’s believed that rotary steerable technologies account for approximately $3.5 billion of the estimated $15 billion directional drilling market.

UAE Test Cases

High-performance mud motors have been used successfully in many deviated drilling operations and have achieved better-than-average ROP rates in three offshore test cases – the Thamama, Hith and Arab formations in the United Arab Emirates.

Seven wells in the Thamama Formation featured multiple target zones and were characterized by hard, Cretaceous limestone, but they presented no sliding issues. The operator used high-performance mud motors to drill the wells, which were not horizontal but had deviations ranging from 0° to 30° and had 8 ½-in. hole sizes.

The high-performance mud motors performed with an average ROP of 28 ft/hr (8.5 meters/hr). The best performance for the motors was 44 ft/hr (143.4 meters/hr), and the worst performance was 17 ft /hr (5.2 meters/hr). The Hith Formation also featured hard drilling conditions, with Jurassic anhydrite and dolomite rock but no sliding issues. The operator again drilled seven hole sections, all deviated but not horizontal, with 8 ½-in. hole sizes and a build section of 25° to 90°. In this case, the high-performance mud motors delivered an average ROP of 18 ft/hr (5.5 meters/hr). The highest ROP was 41 ft/hr (12.5 meters/hr), and the lowest was 9.88 ft/hr (3 meters/hr).

In the Arab Formation, featuring Jurassic carbonate/anhydrite rock, both sliding and directional control challenges were present. The lateral section was +/- 90°. Again, the operator drilled seven 8 ½-in. hole sections with high-performance mud motors.

The operation achieved an average ROP of 18 ft/hr (5.5 meters/hr). The best performance was 31 ft/hr (9.4 meters/hr), while the worst performance was 10 ft/hr (3 meters/hr).

The emergence of multiple technologies to optimize the drilling process can make selection of the proper technology confusing. Understanding reservoir properties along with diligent analysis of the well program, including formation, bit selection, directional program and other factors, must be considered when determining whether an RSS or a high-performance mud motor will achieve the best results in terms of cost and efficiency.

In tight or narrow formations where precise, directional control is needed, RSS are often the optimal choice for achieving drilling optimization and increased ROP. In zones with broader boundaries, a high-performance mud motor can provide results at a lower cost, provided issues such as sliding are carefully examined.

By Ted Christiansen, National Oilwell Varco; and Jim Reed, Optimal Designs

Figure 1: An RFID reader transmits an encoded radio signal to interrogate the tag. 915 MHz and 2.45 GHz represent the higher RFID frequencies, and lower-frequency RFID devices are at 131 KHz, 13.56 MHz or below.

Radio frequency identification (RFID) dates back to the late 1940s with a landmark paper by Harry Stockman titled “Communication by Means of Reflected Power,” where he described a device to aid in the identification of aircrafts – friend or foe. Non-military application of RFID gained momentum in the last 20 to 30 years as the availability of small, low-cost semiconductors (chips) for the tags became possible.

RFID is used in virtually every industry, and new applications to solve old problems are envisioned almost daily. The use of RFID in oil and gas is increasing as well, but there have been challenges because of the physical environment in which these systems would operate.

An RFID system uses tags attached to physical objects or inventory to be identified. The tag includes a small RF transmitter and receiver, as well as a circuit chip to store the encoded data.  RFID tags can be battery-assisted or passive, the latter using radio energy transmitted by the reader as its energy source. An RFID reader, which is a two-way radio transmitter-receiver, transmits an encoded radio signal to interrogate the tag. The tag receives the message and responds with its identification information. The response could be a serial number, product date, etc. The reader typically relays this information back to a computer database.

Figure 2 (left): Magnetic fields travel tangentially to the steel plate in its presence. On the left in Figure 2 is the source, a ferrite-loaded coil antenna. On the right is an identical receive antenna, and in the middle is a steel plate.

The Questions

Several questions should be considered in formulating an RFID solution, and each question cannot be answered isolated from the other questions. The first thought in selecting an RFID solution might be inquiring about the tag size, with consideration of the available surface area to mount the tag.

The tag size and performance is related to its frequency of operation.  Further, the frequency selected can play a factor in the success of the RFID solution, including how the RF waves interact with physical objects, as well as the communication rate and distance with the reader. Suppose the RFID frequency has been selected, and the tag size and antenna performance are satisfactory.

The next step is to evaluate the best location to mount the tag for communication performance with the reader, and assessment of how the performance of the tag changes with the mounting surface. Changes because of the mounting surface can include resonance shift, bandwidth reduction and far-field degradation, which affect the tag’s ability to communicate with the reader.

Figure 3: The environment can change RFID performance. Here, a 915 MHz RFID tag is placed in a complex environment, which affects “read angles” available from the far field pattern.

The objective of this article is to address these questions and expand on the physics behind them, with the intent of educating and empowering the RFID novice with enough knowledge to make wise decisions in creating a tailored RFID solution. A rudimentary description of an antenna will be provided, followed by an overview of available RFID frequencies, which answers the first big question.

In a simple definition, an antenna converts time-varying current to propagating electromagnetic fields, the latter often referred to as radiation, far field or RF fields. The time-varying current is usually implemented as a periodic sine wave, and its periodicity defines the frequency of operation. With the law of reciprocity, an antenna can receive RF fields and convert them back to current with the same level of efficiency as in transmit mode.

To picture how an antenna works, think of it as part of an electrical circuit. There is a source with drive impedance, transmission lines, maybe a matching circuit, and finally the terminals of the antenna. The terminals of the antenna can be seen as impedance with a resistive real term and reactive imaginary term. The resistive real term at the antenna terminal is called the radiation resistance, and it’s based on how well the antenna geometry couples energy into radiation. It determines both the match and the bandwidth for an antenna system.

Figure 4: The electromagnetic field around an antenna can be separated into two primary field regions, near field and far field. The near field also encompasses the immediate reactive field region and the Fresnel region.

For a common 50-ohm system, the impedance should be as close to 50 ohms (resistance to electrical current) as possible. For the common dipole antenna, the radiation resistance is 36 ohms, but for electrically small antennas, the radiation resistance is a fraction of a single ohm.

There are other antenna terms that describe antenna characteristics.  Directivity describes how well the radiation pattern is focused in a single direction. Depending on the reader configuration, the objective might be to have a lot of focus to read at longer distances with a smaller angle of view. Alternatively, it might be preferred to have a wider angle of view with shorter read distances.

Field orientation includes linear and circular polarization. For a linear antenna, the receive antenna needs to be oriented in the same alignment as transmit for detection. This also means that if the receive antenna is 90° rotated from the transmit antenna, there would be no detection at all. The inherent advantage of circular polarization – a rotating linear polarization – is that detection would occur at most angles of observation.

The FCC has defined Industrial, Scientific and Medical (ISM) radio bands, which apply to frequencies available for RFID technology from 6.780 MHz to 5.800 GHz. ISM frequencies of interest for RFID technology are 13.560 MHz, 915.000 MHz, and 2.450 GHz. These frequencies might be recognized, like 915 MHz for cellular technology and 2.45 GHz for Bluetooth and the microwave.

RFID: 4 big questions to ask

1: What fundamentally is an antenna, and what RFID frequencies are available?

2: What are the trade-offs for different antenna topologies?

3: What frequency should I use for my operating environment?

4: What changes in performance occur when the tag is mounted to the surface?

Figure 5 (left): Antenna performance changes when mounted. In the figure’s upper-left quadrant, the tag is mounted in a machined pocket in metal. In the upper-right, the tag is in free air. The tag antenna’s response vs frequency is plotted in the lower-left quadrant, with the free-air tag (red curve) showing a better match with more bandwidth than the mounted tag (green curve). The lower-right quadrant shows the radiation pattern of a mounted tag.

Antenna Topologies, Electric and Magnetic Field Coupling

There are several topologies of antennas, including wire, aperture and microstrip. At 915 MHz and 2.45 GHz, which represent the higher RFID frequencies, a microstrip or patch design is often used to create a quarter- or half-wavelength antenna. Antennas of this electrical size should have excellent radiation resistance and directivity with considerable representation of both electric and magnetic fields.

Lower-frequency RFID devices at 131 KHz, 13.56 MHz and below use a wire configuration in the form of a loop or sequential loops to create a coil. These low-frequency configurations have the electrical length of much less than a tenth of a wavelength, which places them in the unique category of electrically small antennas with very low radiation resistance and low directivity. Because they are not a natural resonating structure, a circuit is needed to tune the reactance to the desired frequency.

It is also common to load the core of these coils with a high-permeability ferrite to increase the flux density and radiation resistance. These low-frequency coil topologies have mostly magnetic field representation.

Whether the antenna primarily uses magnetic field could be an important design criteria based on the environment the tag will be used. Electric and magnetic fields act very differently in the presence of metals and liquids. Magnetic fields are less influenced by losses in liquids since liquids rarely have magnetic material losses. And by boundary condition, magnetic fields move tangentially to iron ore metal surfaces; this means the magnetic fields try to move around metal surfaces. Additionally, magnetic fields can pass through thin metals that do not have iron ore, such as tin and copper.

Electric fields are the opposite. They have high electric losses in liquids, and by boundary condition, electric fields move toward an orthogonal alignment to metal surfaces, which would have the appearance of termination.

The example in Figure 2 shows how the magnetic fields travel in the presence of a steel plate. On the left is the source, a ferrite-loaded coil antenna; on the right is an identical receive antenna, and in the middle is a steel plate. It can be seen how the magnetic fields travel tangentially to (along) the steel plate, instead of terminating orthogonally (directly at) as electric fields would. The magnetic fields even bend around the edge of the steel plate and come down the opposing side to couple to the receive antenna.

This convenient behavior does not happen with electric field antennas operating at higher frequencies, i.e., 915 MHz or 2.45 GHz.

The electromagnetic spectrum

What Frequency Should I Use

For RFID applications, increasing the frequency of operation has the advantage of superior antenna performance in read range and radiation resistance (natural resonant antennas vs electrically small antennas) and increasing the data rate of communication (more cycles per second). However, the higher the frequency, the more the RF fields can be affected by the operational environment.

When considering frequency and wavelength and their influence on physical objects, it helps to view objects as a percentage or multiple of a wavelength. The higher wavelength multiple of a physical dimension, the more “resolution” it has at that frequency, hence becoming more “visible.” Sometimes the goal might be for the object to be visible, and other times it may not.

One example is the walls of buildings; 915 MHz will pass through building walls better than 2.45 GHz because the wall is only half of a wavelength in depth at 915 MHz but almost two wavelengths at 2.45 GHz. Another example is the reading of a tag inside packaging material that is very “lossy” at 2.45 GHz but have no effect at 915 MHz. Thinking about how the proposed frequency of operation will interact in the working environment will help in choosing an RFID solution.

Figure 3 shows a 915 MHz RFID tag placed in a complex environment and the resulting “read angles” available from the far field pattern. This exemplifies how the environment can change the RFID performance.

RFID technology by the numbers

• ISM frequencies of interest for RFID technology are 13.560 MHz, 915.000 MHz and 2.450 GHz.
• At 915 MHz and 2.45 GHz, which represent the higher RFID frequencies, a microstrip or patch design is often used to create a quarter- or half-wavelength antenna.
• Lower-frequency RFID devices at 131 KHz, 13.56 MHz and below use a wire configuration in the form of a loop or sequential loops to create a coil.

RFID-tagged crate

Changes in Antenna Performance Once Mounted

The electromagnetic field around an antenna can be separated into two primary field regions, near field and far field. The near field encompasses the immediate reactive field region; “reactive” implies that external changes to the field in this region have a “reaction” on the source. Still in the near field but decoupled from the antenna is the Fresnel region. And the far field begins where the near field ends, with the common mathematic approximation of 2D^2/wavelength, where D is the maximum dimension of the radiating surface and wavelength is defined by the frequency. Figure 4 shows these three regions.

As mentioned, external field perturbations in the reactive field region, such as dielectric loading or shunt capacitance from a grounded metal surface, can detune the antenna. Other concerns for mounting a tag on a surface is shielding of the antenna far field pattern, which limits the tag’s ability to communicate with the reader.

Figure 5 shows an example of how antenna performance changes when mounted. The tag in free air is shown on the right and mounted in a machined pocket in metal on the left. The bottom-left panel shows the tag antenna’s response vs frequency, where the red curve is the tag in free air, and the green curve is with the tag mounted in the metal substrate.

Note that the red curve – tag in free air – is deeper (better match) and wider (more bandwidth) than the green curve – tag mounted. Recall both match and bandwidth are related to the radiation resistance of the antenna. It should also be noted how the frequency changed from 2.625 GHz to 2.45 GHz. These three changes – match, bandwidth and center frequency – are typical of what happens when a tag is mounted in the presence of metal. The initial antenna was tuned to 2.45 GHz in the metal mounted environment. The solution to this problem is to tune the tag to operate on the intended mounted environment.

This is a case where one tag for both free air and mounted is simply not possible; the physics do not allow it.

Figure 6: The idea of being able to automatically scan pipes as they are trucked in may be good in theory but would be difficult to achieve.

Real-World Environment Example – Stacked Pipe

Imagine drill pipe stacked on a trailer being transported from a pipe yard to the well site. Wouldn’t it be great if the truck could drive through the gate and all the pipes were scanned automatically?  This is a commonly suggested idea, and sounds great in theory; yet it is difficult to achieve in practice. Examining this situation in more detail helps to understand why.

To visualize how the radio signals travel between the tags and the antenna, imagine placing a flashlight at the location of the RFID tag on the pin end tooljoint, perpendicular to the tag. Imagine the light traveling in a straight line, with some diffusion in a conical shape. Suppose there is a “wall” of antennas on both sides and the top of the trailer. The antenna panels are going to receive light only from flashlights that are aimed toward them, where the light is not blocked by an adjacent drill pipe.

Further, the strength of light received varies as a function of the angle between the flashlight and the solar panel. The light from flashlights pointing directly at the trailer’s bed will not be received. The spacing of the joints does have an influence but has limits of practicality because the stack would become too tall. Higher-frequency RFID solutions act like the flashlight analogy so it can be concluded that it will not work for this application.

Low-frequency RFID inductor topologies with a majority of field strength in the magnetic field (RuBee, LF, HF) have an advantage, where line of sight is not needed since magnetic fields are able to bend around adjacent joints. With a properly designed inductive antenna and the appropriate technology (RuBee, LF), this scenario is possible.

In this article, along with the background of what consists of an RFID system and a description of antenna characteristics, the trade-offs of RFID frequencies and geometry topologies were discussed, and the importance of understanding both the reader-to-tag operating environment and the tag mounting environment was emphasized. Lastly, a complicated real-world example in the oil and gas industry was examined to determine if it is possible.

It is clear that RFID has the potential to improve many processes in this industry. However, the challenges in the oil and gas environment – metal, environmental conditions – make the choice of technology difficult. More importantly, the judicious application of RFID in oil and gas must be based on the physics of RFID. When the application of RFID to a real-world scenario is considered, the question should be asked whether the physics support it. If not, there may be another way to solve the problem. This alternative solution may not be flashy or leading edge, but it might just get the job done.

References:

http://en.wikipedia.org/wiki/ISM_band

H. A. Wheeler, “Small Antennas,” IEEE Trans. Antennas and Propagation, Vol. AP-23, No 4, July 1975

http://autoidlabs.eleceng.adelaide.edu.au/Tutorial/1356RFID.pdf

http://cst.com/Content/Documents/Articles/article438/Marc_Ruetschlin_CST_RFID_Europe_2008_online.pdf

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Along-string pressure, temperature measurements in real time can lead to earlier detection, management of  well control incidents in deepwater

By Daan Veeningen, NOV IntelliServ

In the post-Macondo world, government agencies have promulgated significant new safety standards to ensure the safety of workers, environment and assets. These new safety measures and regulations include enhanced drilling safety, increased inspection and improvements to workplace safety regulations. The US Bureau of Ocean Energy Management (now the Bureau of Safety and Environmental Enforcement) panel report regarding the causes of the Macondo blowout, which was released 14 September 2011, is an example of some of the regulations that could take effect.

Figure 1: Wired or networked drill pipe can provide real-time downhole data to supplement a safety management framework system to identify, analyze and control events.

Besides new processes and training for personnel, there is also emphasis on developing and deploying new technology to aid in earlier identification of a wellbore influx, in improved analysis once these well control events unfold and in enhanced ability to regain control. Supplementing surface data with acquisition of downhole data in real time improve the ability to identify, analyze and, ultimately, control events (Figure 1).

Examples of valuable data acquired downhole are annular pressure measurements, downhole sonic and look-ahead seismic measurements. Annular pressure aids in identifying an influx, and acoustic waves may offer insight in pore pressure and trends ahead of the bit. The accurate prediction of formation pressure is not only crucial for casing point selection but most imminently for selecting the optimum drilling fluid density to deliver the hydrostatic density to balance formation pressures.

In particular, downhole sonic and acoustic data represent large data volumes. Transmission to surface relies on wireless protocols, such as mud pulse and electromagnetics. While improvements have been made, the achieved rates are dozens of bits per second (bps) and deteriorate to single bps as drilling depth increases.

Wired or networked drill pipe can offer a step-change in data transmission speed. Networked drill strings incorporate distributed temperature and pressure sensors and have the potential to transform management of downhole incidents, especially in deepwater, where the risks and consequences are significant.

Figure 2: A networked drill string’s distributed pressure and temperature measurement assemblies allow for along-string evaluation of wellbore conditions from near the bit to the surface.

Faster, Bi-directional Data Transfer

A high-bandwidth downhole data transmission system via a wired or networked drill string system, such as the IntelliServ Broadband Network, provides real-time pressure and temperature measurement from discrete locations along the drill string (Figure 2).

Networked drill strings have made significant strides in speed, system integration and the number of measurements afforded. At a data transmission rate of 57,600 bps, the system can transmit data acquired by any of the large service companies and can transmit pressure and temperature measurements from along the drill string by allocation of an additional 57,600-bps bandwidth. This system has been deployed on 90 wells totaling more than 1 million ft.

The bi-directional transfer of information at high telemetry rates through the networked drill string allows for faster update of geology and geophysical information and reduces geological uncertainty. It also provides greater control of the bottomhole assembly while operating rotary steerable tools and conducting formation pressure testing. The ability to send commands to these downhole tools via the broadband network provides instantaneous tool control, real-time tool diagnostics and troubleshooting, replacing the conventional downlinking.

Real-time transfer of high-definition logging-while-drilling information helps subsurface personnel to obtain the facts needed to control placement of the well when it matters most – in real time. Safety – specifically for deepwater operations – may be improved by supplementing downhole information to the existing surface data.

The section below offers examples for each of the “identify, analyze and control” elements of the safety management system.

Figure 3: A formation pressure test tool was used with the bi-directional communication capability on the IntelliServ Broadband Network. Three good tests were achieved in the 14 ½ x 16 ½-in. hole at approximately 15,000 ft in 17 min.

Safe Drilling Margin 

In reference to a safe drilling margin, the panel report’s well recommendations suggest the term should be “expanded to encompass pore pressure, fracture gradient and mud weight.” High-bandwidth bi-directional communication with downhole tools allow the three elements comprising the safe drilling margin to be established independently for surface measurements.

Identifying the pore pressure, the first element of the safe drilling margin, is routinely accomplished with a formation pressure test (FPT) tool. The operation of formation pressure testers is highly efficient using the bi-directional communication capability, as the time to conduct a pressure test is reduced on average by 50% in the Gulf of Mexico. This not only reduces the chance of getting stuck through reduced stationary time, but it also offers quality control in real time during drawdown – even with pumps off – instead of relying on communication via downlinking and mud pulse that require flow.

In a recent deepwater well, 54 FPTs were taken. Nine tests were tight while 39 tests were taken, exploiting the ability for real-time quality control similarly to the feedback when testing on wireline. The 12 ¼-in. testing tool with 14-in. extension pad tested successful in five tests in the 14 ½-in. hole at 18° inclination. A seal couldn’t be established in six tests in the large hole with well inclination below 8°.

The series of 54 FPTs were conducted in 7 min per test on average. This equated to a time savings of approximately 8 min per test in this Gulf of Mexico environment, achieved through efficient two-way communication with the downhole tester.

The quality control eliminated the need for a wireline run to evaluate the formation pressures, and additional savings included time for the actual wireline log, as well as the time for a check trip after the log-run. Figure 3 shows the three good tests that were achieved in 17 min.

The fracture gradient, the second element that comprises the safe drilling margin, is routinely measured by conducting a leak-off test. While tools provided by service companies record annular pressure, a networked drill string system makes this data available in real time as the test is ongoing in the absence of flow. Further, the compounding annular pressure and temperature measurements at various network nodes reveal information about the compressibility and difference in fluid densities through the annulus.

These downhole hydrostatic measurements help identify the third element of the safe drilling margin: true mud weight. The hydrostatic column in the annulus may have heterogeneous fluid densities because of temperature and compressibility effects, as well as the presence of slugs and sweeps. The pressure measurements at various positions of the drill string ease the determination of the safe drilling margin and evaluation of effects that may cause U-tubing or distort observations at surface.

Figure 4 (right): Leak-off test measurements record the annular pressure at four measurement nodes along the drill string.

Earlier Kick Detection

Early detection and quick response time is imperative in deepwater operations. Detecting influxes is challenging when the information is based on surface measurements alone and when data is slow to reach surface.

The Macondo panel report stressed that, especially in deepwater, “prompt kick detection is critical in deepwater operations with a subsea BOP stack. … If the kick is not detected until after the hydrocarbons rise above the BOP stack, then well control response options are severely limited and the risks of a blowout are significant.”

The network drill string’s early identification of kicks improves safety margins as corrective actions can be taken while the event is limited in size and more easily managed. Figure 5 shows an example of a well influx occurring at the bit while drilling, as well as the decision flowchart that is afforded by the networked drill string.

At initial conditions (time t=0), the incoming formation fluids are still located below the pressure sensors, and the absolute pressures and gradients remain unchanged. As drilling goes on, the formation pressure continues to exceed the hydrostatic (dynamically exerted) pressure, and formation fluids continue entering into the wellbore (t=1).

The pressure sensor nearest to the bit (Sensor 1) is the first sensor to record an annular pressure reduction. As the influx height increases to the next sensor (Sensor 2), the corresponding pressure gradient is reduced between the two deepest sensors that are the nearest to the bit, while the gradients in the sections uphole remain unchanged. At times t=2 and t=3, as the wellbore influx passes Sensor 3 and Sensor 4, the gradients  in these subsequent sections decrease as well.

Figure 5: Kick detection can be enhanced using the networked drill string’s ability to monitor and measure changes in the pressure gradient as an influx of formation fluid travels up the wellbore.

In a kick/loss situation, networked drill pipe running in a fully automated managed pressure drilling system delivers a response time of less than 10 seconds, allowing the system to quickly increase or decrease equivalent circulating densities (ECD) and automatically circulate out kicks while maintaining the desired wellbore pressure profile.

The location of the influx and the type of influx can be determined through pressure measurements independently from surface measurements. Once the influx is identified, maintaining and controlling bottomhole pressure is made possible based on direct downhole measurements.

The network’s ability to take multiple distributed pressure measurements along the length of the drill string allows developing well control issues to be accurately analyzed and characterized. The downhole data, independent from surface data, is available both at stationary conditions with the pumps off, as well as with the pumps on. For example, the network’s processing system can determine if the measured standpipe pressure, measured bottomhole ECD or other measured drill pipe or annulus pressures are increased or decreased relative to the expected values.

Figure 6 shows a phenomena in the annulus initially identified at Sensor 1, which has migrated beyond Sensor 2 and Sensor 3. The pressure responses at each sensor – see insert within Figure 6 – demonstrate the pressure response at it travels the annulus toward surface.

The along-string evaluation is not limited to open hole or within casing. In deepwater wells, the marine riser itself can be thousands of feet, and sensors in that section are helpful in analyzing gas migration in the unfortunate event when gas passed the BOPs. This analysis capability then helps in deciding between lining up the mud-gas-separator or to divert the flow overboard.

Figure 6: Downhole data provided by the wired drill pipe help analyze the migration of fluid in the annulus. Six along-string annular pressure sensors record the dynamic pressure over the mud weight, revealing the location of fluids within the annulus. An influx would induce a pressure reduction, while kill mud traveling up the annulus would show a pressure increase.

Wellbore Integrity by Negative Pressure Testing

The leading well recommendation in the panel report calls for “regulations that require the negative pressure testing of wells where the wellbore will be exposed to negative pressure conditions, such as when the BOP and riser are disconnected from the wellhead during permanent or temporary abandonment procedures.”

Today’s procedures and interpretation of negative pressure tests rely on surface measurements for verification of wellbore integrity. Adding complexity to the already limited data stream during the test is the possibility for heterogeneous fluid density columns in the annulus and the chance for a plugged choke and kill lines or misaligned surface valve.

Downhole measurements help analyze independently of surface measurements the pressure buildup that may follow once the drill string is displaced with a lighter fluid (typically base oil or water) following stinging into a downhole circulating packer. Alternatively, the pressure build-up can be monitored downhole once the choke and/or kill line have been displaced with lighter fluid and the BOPs have been closed.

In both methods, the bore and annular pressure measurements at the various measurement stations along the string are independent from surface measurements and complement one another to discriminate from false negatives.

To regain well control, wellsite personnel must circulate out the wellbore influx and replace the fluid column with denser mud. During this process, constant bottomhole pressure must be maintained to prevent additional wellbore influx. Constant bottomhole pressure is achieved by carefully operating the choke to keep adequate backpressure and is historically achieved based on surface measurements.

With the networked drill string, however, wellsite personnel are afforded high-resolution downhole and annular pressure readings along the string. This additional downhole data is available regardless of flow, providing accurate hydrostatic pressure even at typical kill-rates of 10-20 strokes per min.

A pressure gradient between the various measurement stations along the string provides for monitoring the influx and/or the kill mud as it travels up the hole (Figure 6). This method complements – or replaces – the conventional, manual well kill sequence. The kill-sheet may have to be performed under time constraints and stress by personnel who may have limited exposure or experience with well control events.

The additional high-frequency downhole not only improves safety and accuracy but also allows for the well to be dynamically killed, improving efficiency and saving rig time.

Relief-well drilling in the wake of a blowout requires accurate steering to intercept the target well. Steering commands – with confirmation – take seconds compared with minutes without bi-directional wired communication. Additional benefits are offered by the downhole pressure measurements during the dynamic well kill by transmitting data even while experiencing the U-tubing effect at the time of intercepting the flowing target well. The distributed along-string pressure evaluation provides a pressure gradient, which offers additional insights during the well kill and subsequent bullheading operations.

The IntelliServ networked drill string was deployed to drill one of the two relief wells in deepwater Gulf of Mexico in summer 2010. Specifically, experts involved were keen on identifying the downhole pressure upon interception with the flowing well to analyze the pressure. Ultimately, the top kill controlled the well.

Deepwater operations face new safety standards to ensure the safety of workers, environment and assets. Networked drill strings offer downhole measurements in real time for the identification, analysis and control independently from surface measurements. This redundancy aids the safety in three examples:

• First, the networked drill string provides downhole data independently from surface measurements to identify pore pressure, fracture gradient and effective mud weight that comprise the safe drilling margin;

• Second, the independent along-string pressure evaluation provides early kick detection and improved ability to analyze and control an influx even with heterogeneous mud column; and

• Third, methodologies are offered to conduct negative pressure tests to bolster the conclusiveness of the inflow simulation. An influx can be identified and analyzed even if it has already passed the BOPs into the riser. This methodology helps decide between lining up the mud-gas-separator or diverting the flow overboard.

Beside the annular and bore pressure sensors that are currently available, developments are ongoing to determine flow rate at distributed measurement stations along the networked drill string. These flow rate sensors, as well as fluid identification sensors, would provide additional means for kick detection and lead to better well control.

By David Pavel, Weatherford International; Gavin Humphreys, Stena Drilling

Installing specialized equipment, such as a rotating control device, on deepwater rigs can be cost-prohibitive as there is still a relatively small number of MPD applications in that segment.

The rocks being drilled today demand more than a better set of tools; they require a different approach to well construction. That change is occurring in the form of managed pressure drilling (MPD), which resolves many traditional subsurface problems with the visibility and control that comes from replacing the rig’s traditional open-to-the-atmosphere circulating system with pressurizable, closed-loop technology.

Nowhere is this ability to minimize and eliminate subsurface problems more important than in the extremes of deepwater drilling. In these applications, where process safety is paramount, narrow-to-nonexistent drilling windows and high-temperature, high-pressure wellbores routinely challenge safety, economics and the ability to drill the well.

Despite its advantages, application of deepwater MPD has been limited. Time constraints drive an array of costs, and people and deployment limitations make it especially difficult to deploy the technology on deepwater semisubmersibles and drillships.

Overcoming these constraints requires a coordinated industry effort focused on the development of guidelines, procedures and standards for equipment procurement, rig modification and design, and training for all stakeholders in the drilling process.

The goal is an MPD-ready rig. Today, however, “ready” describes a rig that is ready to accept MPD components, not one that has already been outfitted with MPD components. Parameters such as riser IDs, rotary table IDs and deck requirements can accommodate MPD equipment. Readiness also depends on experienced personnel, cost efficiency and the ability to deploy an MPD system concurrent with an operator’s drilling schedule.

There can be many constraints to the deployment of MPD. Fundamentally, MPD is still a niche player in deepwater provinces. Operators and drilling contractors have limited expertise in planning and executing MPD operations. Each application typically begins anew, requiring a lengthy training process for rig and operator personnel on safety and operational procedures. This situation is further complicated by such variables as rig configuration and type of MPD application.

Equipment cost is primarily an issue of scale. Highly specialized marine MPD components, such as Weatherford International’s Sea Shield series of riser-integrated rotating control devices (RCD), are being used effectively aboard deepwater vessels. Still, the relatively small number of applications makes MPD capital equipment expensive and lengthens procurement times even for ancillary equipment items.

Weatherford’s RCD can be made up below the tension ring so no modifications are required to the riser’s telescoping slip joint or the rig’s mud returns system. MPD components and configurations must be clearly specified for various MPD applications to aid planning and shorten lead times.

New and existing rigs

The shift to MPD-ready rigs must address both the existing rig fleet and newbuilds. Perhaps the greatest challenge in refitting an existing rig is the general lack of standardization across deepwater rig designs. As a result, it is difficult to deploy an MPD system on an ad hoc basis. Each requires a customized approach.

While most MPD equipment components are familiar to rig operations, an MPD package requires special accommodation that is typically problematic for existing semisubmersibles and drillships. A rig survey is usually performed to establish deck loads and footprints, power and other MPD requirements. Modifications are often required, which can add significantly to time and costs.

In some cases, major modifications must be made to riser components, such as slip joints and tension rings. The long lead times that result can exclude MPD as a potential solution for an operator or a particular well.

Newbuild rigs similarly require special design considerations. However, they present a different challenge. In recent times, many deepwater rigs have been built on speculation, without contracts and by non-drillers who are not attuned to the subsurface demands driving MPD use.

The industry must communicate the desirability of MPD-ready designs along with the required specifications if MPD is going to be available when needed.

Making MPD more available for deepwater drilling requires a coordinated effort on multiple fronts to streamline and standardize as much of this process as possible. At stake is an immediate improvement for process safety and the ability to mitigate and eliminate many pressure-related deepwater drilling hazards.

This MPD effort must initially develop a procurement process to reduce the cost and time of acquiring and deploying equipment to location. MPD components and configurations must be clearly specified for various MPD applications to aid planning and shorten lead times. To reduce lead time, drilling contractors will deliver ancillary equipment while service providers will continue to supply MPD-specific equipment.

Rig modifications must also be identified and templated to provide a clear process for implementing an MPD refit. Specifications should be developed for MPD “kits” to match MPD configurations to various rig models. The specs should describe such basics as deck loads and footprints, as well as flow lines, air, electrical and hydraulic connections.

Other factors should be considered as well. For instance, the riser connectors should accommodate MPD riser components, including the flow spool, operational annular preventer and RCD. The riser ID must allow pass-through of the bearing assembly, which involves the tension ring, telescopic slip joint and upper ball joint. The rotary table ID should accommodate pass-through of MPD riser components consisting of a flow spool, operational annular preventer and RCD.

Interface documentation between the MPD process and rig is a necessary objective. In the long term, this document will become an industry best practice. Generic procedural templates can be developed that address about 80% of the MPD process, with the rest customized according to job, rig and well factors.

Efforts by IADC to develop MPD best practices are a welcome step toward this level of documentation. Similarly, IADC provides examples in industry training.

Development of industry training standards for MPD is critical. Safety and performance depends on an understanding of MPD operations that equals conventional drilling operations. Achieving this routine level of MPD requires a thorough training effort at all levels. Training courses similar to existing well control courses must be developed for contractor and operator personnel.

The growing number of MPD systems installed aboard deepwater vessels will lead to continuing improvements in process safety as rigs regularly apply MPD to manage wellbore pressures. Time and cost constraints will continue to diminish with increased use and improved processes.

There are MPD-ready deepwater rig designs that provide built-in capability to address the availability issue.

Stena Drilling’s DrillSLIM drillship and semisubmersible designs are smaller vessels aimed at reducing the cost of deepwater wells by slimming down the well design and drilling the wells with a high-pressure riser and surface BOP (SBOP) on which the MPD surface equipment is installed.

The Stena “Advance” semisubmersible design features an independently compensated MPD platform configured to support an inner high-pressure riser, locked into the lower marine riser package (LMRP) and an MPD frame in which the MPD equipment is permanently installed.

The MPD drilling process then takes place through a high-pressure inner riser, with returns fluid being diverted below the RCD, through the choke manifold and finally back to the shale shakers.

With, for example, the main body of Weatherford’s riser-integrated rotating control device permanently installed on the rig, the provision of dual-gradient drilling (DGD) could be achieved. DGD is a deepwater technique in which the riser is displaced with seawater or the riser is partially evacuated to reduce the weight of the mud column from the seabed to the rotary table.

Further, with this equipment, permanently installed pressurized mud cap drilling techniques, which enable drilling in total loss circulation wellbores while maintaining pressure on the drilling annulus, could also be achieved.

Building MPD capabilities into the rig provides a solution from the outset. The “DrillSLIM” or “Advance” designs cut or eliminate lead times because equipment is in place and contractor personnel are already trained. Drilling operations can transition from conventional drilling to MPD methods as and when needed to address wellbore conditions.

The availability of MPD-ready rigs also encourages the incorporation of MPD capabilities into candidate selection and well planning.

As MPD becomes more commonly applied, ownership of critical riser items will transition to the drilling contractor, including the flow spool, operational annular preventer and RCD housing. This will enable MPD deployment as a standard package – a plug-and-play solution.

The development and refinement of industry standards and procedural templates, along with a growing industry expertise, will continue to enhance performance and reduce costs.

These advances, along with the growing subsurface demands and uncertainties, will yield an MPD-ready rig fleet that will write the next chapters in deepwater drilling operations.

The International Association of Oil & Gas Producers (OGP) has asked the European Commission to look to legislation in the form of a directive that would allow member states to adjust to local circumstances and align with existing regulatory frameworks.

IADC has been involved with development of OGP’s position paper, which was delivered to the commission’s Directorate-General for Energy in January.

The paper notes that the offshore E&P industry has developed recommendations for improving well incident prevention, intervention and response capability over the past couple of years. This work has already achieved better engineering design and well operations management, improved capping devices, and enhanced oil spill preparedness and capability.

86 groups object trade agency reorganization

Eighty-six groups representing the business and agricultural communities, including IADC, jointly wrote to US President Barack Obama expressing concerns over a proposal to merge the Office of the US Trade Representative (USTR) with five other agencies into a single cabinet-level department.

By balancing the interests of various constituencies and agencies, the USTR provides assurance to stakeholders “that no one has a thumb on the scale,” the letter stated. As a separate entity, the USTR is able to act responsively to negotiate, implement and enforce US trade objectives. The USTR is actively involved in growing US exports, eliminating foreign market barriers and improving the overall competitiveness of US farm and manufactured goods and services in the global economy.

IADC executive VP – government affairs Brian Petty, in his capacity as ITAC2 chairman, counsels the US Trade Representative and the US Secretary of Commerce on international trade issues.

Industry comments on draft PEIS for OCS

Providing comments to be considered before the Draft Programmatic Environmental Impact Statement (DPEIS) is finalized for the proposed 2012-2017 Outer Continental Shelf (OCS) leasing program, seven industry groups, including IADC, reiterated disappointment in the limited scope of the DPEIS. However, the groups also expressed support for the work of the US Bureau of Ocean Energy Management (BOEM) in preparing for the DPEIS.

Comments were submitted in January to James Bennett, BOEM Division of Environmental Assessment chief. They pointed to the missed opportunity to increase access to additional OCS energy resources in the Eastern Gulf of Mexico, offshore Alaska and on the US East Coast, especially offshore Virginia. However, with as many as 15 lease sales among the six OCS planning areas in the proposed action plan, industry believes the DPEIS includes an acceptable range of offshore access.