SPE/IADC 163452

HPHT Well Construction with Closed-Loop Cementing Technology Don Hannegan, Tim Dunn, Weatherford International Ltd., Dennis Moore, Marathon Oil Corporation, Dr. Ken Gray, University of Texas at Austin

Copyright 2013, SPE/IADC Drilling Conference and Exhibition This paper was prepared for presentation at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, The Netherlands, 57 March 2013. This paper was selected for presentation by an SPE/IADC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers or the International Association of Drilling Contractors and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers or the International Association of Drilling Contractors, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE/IADC copyright.

Abstract Achieving successful isolation of potential flow zones during well construction in deep fault-segmented HPHT basins is often a formidable task. These wells, often drilled from floating rigs, tend to present rapid departures from more normal conditions to very high degrees of overpressure, elevated temperatures and where formation pressures often approach fracture gradient. Further, once overpressure is geologically established in isolated pressure compartments, reservoir fluids tend to migrate vertically via hydro-fracturing to shallower depths.18 Challenges associated with cementing operations include actual leak-off test value (LOT) vs. predicted, margins of error in mud weights estimated, and risk of inducing a fracture during pre-flush and slurry displacement. If the open hole was under-reamed, the actual fracture pressure may be reduced by an unknown amount. Wellbore strengthening operations and associated procedures add additional formation fracture gradient uncertainty.4 This presentation speaks to applying the principals of Managed Pressure Drilling (MPD) and recent refinements of its practice to cementing processes. Precise flow in/out measurements in real-time, ascertainment of actual downhole pressure environment, ability to conduct frequent dynamic formation integrity tests (FITs) without drilling interruption and use of PLC choke systems are applicable strengths19,20,22. API Standard 65 - Part 2, Second Edition, December 2010 - Isolating Potential Flow Zones during Well Construction will be referenced to illustrate C-LC applications. Preparatory - quantify the stability of the wellbore with frequent dynamic FITs (without exercising the BOP) and assurance of hole cleaning during pre-flush. Displacement - optimize fluid dynamics and ascertain in real-time an induced fracture. Curing - maintain more consistent annulus pressure on rigs experiencing wave heave, backpressure applications for minimizing the risk of channeling and/or help ensure the column of plug in the tubing string is balanced with the annulus Testing - Use of a rotating control device (RCD) and process logic controlled (PLC) Choke to pressure test plugs after tagging in lieu of using dedicated cementing equipment. Introduction Not all wells that are drilled and casing strings cemented in place during well construction are problematic. However, HPHT wells, depleted reservoirs, and narrow margin drilling conditions and particularly those in deep water have a history of presenting difficult to impossible execution of primary cement placement by manipulation of the traditional variables of cement density, flow rate, fluid viscosities and mechanical staging devices. Cementing operations on floating rigs experiencing wave heave contribute to the challenge.

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API Recommended Practice 65 - Part 2, First Edition (May 2010) and API Standard 65 - Part 2 (December 2010), both entitled - Isolating Potential Flow Zones during Well Construction are well-respected industry documents whose purpose includes guidelines before, during and after cementing operations. The primary difference between the two is that the latter was issued in a post-Macondo environment and a number of shoulds became shalls. Therefore, the applicable document referred to frequently in this paper is API Standard 65 -Part 2;

This document was prepared with input from oil and gas operators, drilling contractors, service companies, consultants and regulators. It is based mainly on experiences in the United States outer continental shelf (OCS) and deepwater operating areas of the Gulf of Mexico, but may be of utility in other offshore and land operating areas. The content of this document is not all inclusive and not intended to alleviate the need for detailed information found in textbooks, manuals, technical papers, or other documents. The formulation, adoption, and publication of API standards are not intended to inhibit anyone from using any other practices. The objectives of this guideline are two-fold. The first is to help prevent and/or control flows just prior to, during, and after primary cementing operations to install or set casing and liner pipe strings in wells. Some of these flows have caused loss of well control. They threaten the safety of personnel, the environment, and the drilling rigs themselves. The second objective is to help prevent sustained casing pressure (SCP), also a serious industry problem.1

Achieving successful zonal isolation in the presence of a potential annular flow requires not only the modification of the cement properties to facilitate control of migrating formation fluids but also several other requirements. Referencing API Standard 65, Part 2, Section A.12, those requirements involve:

a stable wellboreno losses or gains, adequate annular circulating flow clearances, proper drilling fluid conditioning and hole cleaning prior to cementing, spacer design, casing centralization, proper fluid dynamics during circulation and placement of cement to achieve drilling fluid

removal, tripping requirements, drilling techniques, well monitoring, proper WOC time and associated rig operations, sustained hydrostatic pressure during cement curing, no wash pipes in the annulus that negates BOP function, use of mechanical barriers when appropriate1

The requirements highlighted in bold italics above comprise the objective scope of Closed-Loop Cementing applications. Additionally, the process logic controller (PLC) software associated with a MPD choke manifold system provides additional documentation for supervisory control and data acquisition (SCADA) for onsite and offsite decision-making. These data also provide operational inputs for improved cementing, hydraulics, and wellbore behavior quantifications.22,24 Figure 1 below is a simplified MPD and closed-loop cementing schematic applicable for use on a deepwater rig. In this example the RCD is configured below the marine riser tension ring (BTR RCD). When the body of the RCD is absent its bearing & annular seal assembly, conventional returns are taken, as usual, via the marine diverter under the rig floor from which they gravity flow to mud reconditioning equipment. When the RCDs bearing & annular seal assembly is present, MPD returns are taken via flexible flowlines to the dedicated MPD choke manifold. The catenaries of the flow lines serves to compensate for the relative movement between the riser and the rig. The annular BOP immediately below the BTR RCD serves two purposes; facilitate safer riser de-gasing in event of an influx while drilling conventionally and during MPD operations, facilitates removal and replacement of the bearing & annular seal assembly of the RCD.6

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DesignObjectives Circulateconventionallyviarigsdiverterandnormalflowline

Saferriserdegassing,ifneeded Circulateviaclosedsystem

MPD&ClosedLoopCementing

Buffer Manifold

Rig Choke Manifold

Trip TankMPD Choke Manifold

Rig MGS

High Flow MGS

Gas to vent

Gas to vent

Shale ShakersRiser Boost Pump

Riser Boost Line

Choke Line

Subsea BOP

Kill Line

BTR RCD

Annular BOP

Figure 1: Deepwater Closed-Loop Drilling & Cementing Schematic. Closed-Loop Cementing While not the right solution for every well, Closed-Loop Cementing:

Makes it possible to verify formation containment capability prior to running casing. Provides more precise spacer & slurry displacement information for comparison with conventional

cementing calculations. Enables detection of an induced fracture during cementing operations. Allows annulus backpressure to be applied via a choke or backpressure pump and adjusted as required to

achieve the desired pressures on the formations throughout the entire cementing process. Improves the quality of real time documentation for supervisory control & data acquisition (SCADA), on site

and off site.5 (Ref. DCTZ Applying MPD Principals to Cementing Operations, Galveston, October 25, 2012)

The technology is the result of applying two MPD-related capabilities to cementing operations:

Constant Bottom Hole Pressure (CBHP) variation of MPD An adaptive drilling process used to precisely

control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. (Ref IADC UBO/MPD Committee Glossary of Terms)

For given downhole conditions (bottom hole temperature, MW, flow rate, ROP, wellbore geometry, cuttings density, etc.,) the practice of conducting frequent dynamic formation integrity tests while drilling the new hole demonstrates positively what pressures the formation will withstand during the planned cementing operation. (Ref. BSEE presentation by Hannegan, January 23, 2012).4

These methods applied to cementing for well construction and plug & abandonments enhances the evaluation of cementing sequences by providing additional parameters to evaluate and take into consideration. Closed-loop cementing enables modification of the fluid properties to more efficiently displace the drilling fluid for

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better cement to casing and formation bond. Rather than design a fluid that is difficult to control and maintain the desired the rheological characteristics used in modeling, the rheological properties of spacers and cement that will effectively displace 100 percent of the drilling fluid may be achievable by implementing closed-loop cementing techniques. A purpose of this body of work is to elaborate on some of the key requirements that operators may find helpful towards compliance with the intent of API Standard 65 by teaching how MPDs specialized equipment and technology improves chances of getting a good cement job right on the first attempt: CBHP MPD makes it possible to:

Reduce pressure cycling, Improve accuracy of downhole calculations, Provide improved data for planning cement jobs, and Optimize casing running

Closed-Loop Cementing makes it possible to: Respond to events in real time, Impose annulus pressure as desired, Create additional documentation via MPD equipment data acquisition system, and Improve onsite and offsite monitoring capability.4

Typical cementing challenges API Standard 65 teaches this conventional wisdom:

With the intent of achieving successful zonal isolation for well construction and reservoir isolation for plug & abandonments, a plan must be developed to monitor and control static and dynamic fluid pressures of the drilling fluid column such that ECD is maintained within appropriate limits. Static fluid pressure should be sufficient to contain maximum open hole formation pressure and minimize wellbore stability problems, while dynamic fluid pressure should be controlled to minimize fracturing of an exposed formation unless required by wellbore strengthening. Offset well files should be reviewed for indications of loss circulation, stuck pipe, significant borehole enlargement, etc., and the ECD management plan should be modified to mitigate these problems. ECD increase in high-angle and horizontal wellbore sections should be addressed in the plan, as the formation fracture gradient will remain constant in the horizontal section of the well while fluid friction pressure will increase.1

Given a calculated or best guess pore pressure/fracture gradient determination, the wellbore geometry (casing design), and fluid characteristics, cementing companies can run simulators that provide a model of the equivalent circulating densities (ECDs), flow characteristics (flow in & flow out, u-tubing, etc) and some prediction of being able to effectively isolate the wellbore annulus behind casing if the pipe eccentricity and centralization data input to the simulator are all accurate and valid for preplanning stages into the actual execution of the primary or remedial cement placement.11 What can be recorded today to effectively measure the success or failure of a primary cement job - the cement bond log, rates of pumping & displacement of cement, cement fill in the annulus can be estimated using lift pressure recorded by assuming fluids profiles in the annulus are uniform and have distinct separation boundaries (i.e., no channeling or losses), recording of cement, spacer, mud volumes and densities. In most cases, the combination of even the best cement design and execution according to plans do not deliver the desired results. Having the means by which more relevant and real-time pre-cementing drilling parameters can be obtained (open-hole pressure gradients from previous casing shoe to TD identification of ballooning formations, etc), flow characterization(prediction and minimization of u-tube and control rate in/rate out), understanding cement hydration and the effect it has on hydrostatic pressure and being able to control and maintain an effective overbalance pressure to further improve the primary cement design can only prove to be a benefit. Another challenge is the displacement process. Monitoring the backside parameters accurately will help with calculating the displacement required to bump the plug. In many cases displacement calculations to bump the plug are inaccurate due to air entrainment or miss-measurement of the displacement tanks on the pumping unit. Understanding the objectives of a primary cement job, being able to execute the primary cement job and

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adequately interpreting the results have ultimately been the criteria of a success or a failure. Whether success is a leak-off test, open-hole kick-off plug, isolation of a hydrocarbon bearing zone of interest, or a fresh water zone that must be hydraulically or mechanically isolated and protected, the tools and methods that operators and service companies employ today that can be controlled and monitored are not always enough to provide the expected nor the desired results. Lost Circulation Increases Risk for Loss of Well Control Incidents API Standard 65 teaches that lost circulation before, during, or just after primary cementing.

a. Can cause a failure to maintain an overbalance across potential flow zones exposed in the wellbore whereby:

an inadequately designed cement slurry (density too heavy, etc.) fails to reach the designed depth for the TOC column;

or the drilling fluid column is reduced or falls back or goes on vacuum; and either one of these shortened columns results in an insufficient hydrostatic head

pressure to overbalance formation(s) pore pressures. b. Has often been found by investigators as the root cause for many of the loss of well control (LWC) incidents experienced in offshore drilling operations. c. Can induce loss of well control (LWC)16 incidents at any depth in the well construction process from soon after spudding (starting to drill) the well to drilling the well at total depth when conditions occur such as:

structurally weak zones are exposed in the wellbore; naturally occurring leak off flow paths are encountered such as fractures, faults, vugs,

caverns, etc.

As mentioned above, lost circulation during primary cementing operations may cause reduced hydrostatic pressure and underbalanced conditions when losses cause the drilling fluid column to fall to create an underbalanced condition. For example when heavier density (than the drilling fluid) cement slurries are removed from the annulus by total or partial lost circulation (cement flows into weak zones), the top of cement (TOC) can be much lower than the designed TOC depth. This substantially decreases the annular column hydrostatic pressure across potential flow zones within the cemented annulus. This decreased hydrostatic pressure allows formation fluids to influx into the wellbore which starts annular flows that can lead to LWC incidents. In some cases, operators perform FIT16 or LOT16 measurements after the initial casing shoe test while drilling critical hole intervals or after drilling the entire hole section. This practice helps confirm that lost circulation can be prevented by the integrity of the open hole to contain pressures generated from deeper drilling and/or from operations to set casing/ liner pipes (higher ECD in running pipe and primary cementing). Successful cases over the last 50 years have proven that this practice can successfully predict cementing placement without losses and/or allow for pre-job changes in the cementing design lan that result in successful primiary cement operations.1

Frequent FITs are integral to the practice of Closed-Loop Cementing The ease at which one may conduct frequent FITs with a MPD kit, called dynamic FITs, is a key aspect of the practice of Closed-Loop Cementing. However, FITs are often confused with LOTs. API Standard 65 takes care to distinguish one from the other.

Formation integrity tests (FIT) and Leak-Off Tests (LOT), also known as pressure-integrity tests or pump-in tests (PIT) are carried out during the drilling phase after a string of casing has been cemented and before a new section of hole is drilled. In these types of casing shoe tests, the cement at the casing shoe is drilled out and a section of new hole (typically 10 ft to 20 ft) is drilled, the BOP is closed around the drill pipe, and the well is slowly pressured up using mud.2

Most governmental regulatory organizations maintain criteria regarding verification of casing shoe integrity.

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FITs are carried out until a pre-determined test pressure is reached, confirming that the formation at the casing shoe can sustain this pressure. The test is characterized by a linear response of downhole pressure vs. volume pumped (or time if the flow rate during the test is constant). These tests are frequently used on production wells in mature fields, where fracture gradients are already well-understood. The limit test is used to confirm the margin necessary to drill the next hole section, without leaving a fracture (i.e. a potential point-of-weakness) at the previous casing shoe.

LOT tests are carried out at higher pressures to characterize the phenomenon of leak-off into the formation at the casing shoe. Leak-off is characterized by a deviation from linearity on the pressure vs. volume curve. It is associated with the initiation of a fracture at the casing shoe. Pumping beyond the leak-off point will extend the fracture. A shut-in period is normally maintained after pumping to monitor the behavior of downhole pressure. During an extended leak-off test, backflow of drilling mud after shut-in is monitored in order to characterize in-situ stress values. Both LOTs and LOTs may be repeated to verify the results of, or assess the changes induced by, earlier tests, drilling operations, and/or remedial squeeze jobs.1

This discussion in the API document teaches the differences between FITs and LOTs under the assumption, or at least implies that the weakest point is the last casing shoe. In HPHT wells, that may not to be the case. The weakest point from a structural integrity point of view may be encountered while drilling the open hole at a depth well below the last casing shoe.4 Additionally, one must also consider that Fp estimates typically assume shale, but you may be drilling and/or cementing in sand. It is important to recognize that a FIT is analogous to proof testing a pressure vessel for assurance it is fit for purpose. Assuming the vessel passes the proof test; no permanent deformation occurs and consequently its pressure containment value (with safety factor) is not diminished. A properly conducted FIT similarly poses little or no risk of reducing the fracture pressure gradient. This analogy ends, however, when one considers a pressure vessel is a fixed object where only periodic proof testing is quite sufficient for desired assurances. In drilling operations, the structural integrity of a wellbore invariably changes with each formation encountered, or each stand of pipe drilled, or in some cases, each additional foot of depth.13 This can imply a best practice would be to conduct FITs frequently when drilling critical or trouble zones to be assured the wellbore is capable of withstanding the surge pressures associated with subsequent casing running operations and the dynamic pressures expected in the planned cementing operations. On the other hand, a LOT is analogous to a burst test of a pressure vessel, which causes permanent deformation. A LOT invariably reduces the fracture pressure gradient afterwards. The greater the permeability of the rock, the more this is the case. However, LOTs are invaluable in context of well control to determine the maximum surface pressures which may be applied when circulating out a kick. However, one must realize that beyond that primary purpose, LOTs and XLOTs (extended leak-off tests) may do more harm than good if the intent is to not diminish the fracture gradient from what it would otherwise be.11,27 Figure 2 is an illustration of the manner in which LOT and XLOTs risk hydraulically fracturing the wellbore to a point of permanent fracture propagation, particularly XLOTs.

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Figure 2: Typical LOT or XLOT results in permanent deformation of the wellbore Recently initiated work on Leak-Off Signatures, Interpretations, and Applications (Gray, 2012) seeks to more accurately quantify both the static and dynamic pressure vessels involved in LOT, XLOT, and FIT testing procedures. While the open-hole below the casing shoe is usually assumed to be a fixed object, the actual pressure-affected hole size increases as filtrate (and mud) are forced by differential pressure into the rock formation and/or into existing or induced fractures. Thus, the volume of drilling fluid actively participating in pressure changes is more than the drilled-hole volume, and surrounding rock volume is involved as well. And to emphasize what has been stated earlier, the weakest location may not be the last casing shoe, but rather in formations being drilled below the last casing shoe. When the initial part of the LOT is non-linear rather than linear, it is more difficult to determine the leak-off pressure at the upper part of the plot, prior to fracture propagation pressure (FPP). Moreover, if the already cemented shoe allows some pressure transmission because of a faulty seal or micro-channel behind the pipe, the resulting LOT will reflect that and the usual determination of least horizontal stress may reflect an already penetrated, cased-off formation rather than the newly-drilled one. Conducting frequent dynamic FITS have potential to provide valuable information to cementing simulator models and allow for real-time adjustments to the planned cementing program if a FIT fails and in effect becomes a LOT showing a lower value than predicted. In this respect, they also minimize the risk of a surface or subsurface blowout while drilling the open hole.12 If loss circulation material (LCM) has been deployed, this inherently adds to the relative unknown of the fracture gradient. In this case, dynamic FITs may be helpful to quantify the effectiveness of LCMs and other wellbore strengthening techniques. Dynamic FITs with a MPD kit Dynamic FITs are performed with rig pumps, through the bit and while rotating the drill stringthis, which captures all of the aspects that impact the ECD in real-time. Surface backpressure is applied by the MPD system, eliminating the need to use the BOP in the process. The ease of dynamic FITs supports the practice of conducting them often in critical zones rather than making the usual assumption that the weakest point coincides with the casing shoe depth. Their purpose is to:

Demonstrate that it is safe to continue drilling into anticipated pressure conditions.

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Determine if the wellbore can withstand planned casing and cementing operations without inducing fractures and if not, what conditions must be met.

Best cementing practices require a stable wellbore no gains or losses. Conducing frequent dynamic FITs contribute greatly towards being able to achieve that objective while drilling the open hole to be cased (or lined) and cemented later. Please keep in mind that dynamic FITs with a state-of-the-art MPD kit are conducted without drilling interruption and without using the rigs BOP to apply backpressure. Instead, MPDs dedicated choke system provides the means of backpressure and the time and temperature corrected algorithms of its software provides precise real-time measurement of flow in-out.22 Figure 2 below is an example of a dynamic FIT. In this case the operator wished to confirm wellbore integrity to 15.8ppge. The test confirmed wellbore integrity to that value as evidenced by the fact no losses began to occur up to the FIT test-to value. No losses indicate no fracture or promulgation of fracture has occurred to the wellbore and consequently no risk of fracture promulgation which may influence future fracture pressure values.

Figure 2 Dynamic FIT performed in order to check for the planned FIT (15.80 ppg). Note that Flow IN and Flow OUT lines are not diverging independently of the surface backpressure applied up to the desired FIT value.28 Figure 3 below is an example were the operator hoped the FIT value was at least 14.83ppge. Formation breakdown began to occur before that value was achieved, informing the operator that, in fact, the actual LOT value was less than expected. This real-time information provides advanced notice that adjustments may need to be made to the planned ECDs, casing running speed, and/or the cementing program itself. This information may also indicate the need for a casing set point shallower than plan; run a liner or perhaps other mitigation action.

0 100 200 300 400 500

Time

SurfaceBackPressure(psi)

SBP

15 15.1 15.2 15.3 15.4 15.5 15.6 15.7 15.8

Time

ECDatCsgshoe(equiv.ppg)

ECDCsgshoe

30 40 50 60 70

Time

MPDChokePosition(Open%)

Chkposition

350 400 450 500 550 600

Time

FlowIN/OUT(gpm)

FlowINFlowOUT

SPE/IADC 163452 9

Figure 3: Dynamic FIT performed in order to check for the planned FIT (14.83 ppg). Note that Flow IN and Flow OUT lines are diverging, indicating losses before the expected value was achieved. The FIT therefore established a LOT value less than expected.28 And there is a bonus in respect to well control for conducting frequent FITs when drilling in troublesome zones. Underground blowouts involve a significant downhole flow of formation fluids from a zone of higher pressure (the flowing zone) to one of lower pressure (the charged zone or loss zone.) They are the most common of all well control problems. Most underground blowouts that occur while drilling result from lack of sufficient kick tolerance. Kick tolerance is the kick intensity (amount of underbalance) that can be shut-in without exceeding the fracture pressure of the weakest exposed formation after taking a given volume kick12. If leak-off occurs before the FIT test-to value is achieved, this very well may serve to enable drilling decision-makers to avoid an underground blowout further downhole by reevaluating their kick tolerance values and have sufficient time to take corrective actions. Figure 3 below is an example where the operator desired to know if the wellbore integrity could withstand 500 psi surface backpressure. As evidenced by the absence of any indication of losses, the dynamic FIT provided assurance the casing shoe has ECD integrity up to 15.8 ppge.

Figure 3: A dynamic FIT was conducted to determine if the wellbore was able to withstand 15.8 ppg EMW without incurring losses. The test confirmed within a matter of minutes and without drilling interruption that the planned EMW is within the pressure containment cabability of the wellbore.

750 800 850 900 950

Time

FlowIN/OUT(gpm)

FlowINFlowOUT

350 375 400 425 450 475 500 525 550

Time

SurfaceBackPressure(psi)

SBP

42 43 44 45 46 47 48

Time

MPDChokeposition(open%)

ChkPos

14.6 14.65 14.7 14.75 14.8 14.85 14.9

Time

PWDreading(equiv.ppg)

PWD

120gallosses

0 100 200 300 400 500

Time

SurfaceBackPressure(psi)

SBP

15 15.1 15.2 15.3 15.4 15.5 15.6 15.7 15.8

Time

ECDatCsgshoe(equiv.ppg)

ECDCsgshoe

30 40 50 60 70

Time

MPDChokePosition(Open%)

Chkposition

350 400 450 500 550 600

Time

FlowIN/OUT(gpm)

FlowINFlowOUT

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Although a dynamic FIT may yield information the drilling program would find disappointing and require adjustments to the the fluids program, circulating rate, setting a casing set point shallower than planned, or necessate running a liner, it is unquestionably better to learn sooner than later in respect to the planned cementing program. Figure 4 below is such an example, where the operator learned that the pressure containment capability of the wellbore was less than expected and planned for.

Figure 4: A dynamic FIT was conducted to ensure the wellbore is capable of withstanding 14.83 ppg EMW. Flow-in and flow-out lines are diverging at 500 psi surface backpressure applied. LOT reference value was reduced to 14.77 ppge.

Computer Simulations

As is true with many areas of study, computers have greatly improved the design process for well cementing. Using computer simulators, the engineer can tailor the cementing process to account for an individual wells unique conditions. It is no longer necessary to rely on general rules of thumb. Each cementing service company has its own simulator. Simulators are also available from third party vendors. These simulators vary in their capabilities and strengths. Typical capabilities include:

Flow rate and U-tube calculations to predict whether the cement job can be performed within the pore pressure/frac gradient window, considering ECD;

Displacement efficiency;

Foam cementing calculations;

750 800 850 900 950

Time

FlowIN/OUT(gpm)

FlowINFlowOUT

350 375 400 425 450 475 500 525 550

Time

SurfaceBackPressure(psi)

SBP

42 43 44 45 46 47 48

Time

MPDChokeposition(open%)

ChkPos

14.6 14.65 14.7

Time

PWDrea

120 gal losses

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Circulating and post cementing temperature profiles;

Swab and surge pressures.

As with any computer program, the quality of a cementing simulators output depends on the degree to which the input variables are known. It is not likely that a simulator can provide a single right answer. However, by bracketing variables, the engineer can gain insight that will assist in achieving zonal isolation.

The information entered into the computer simulation should be as accurate as possible. This information should include actual mud, spacer, and slurry rheologies, actual caliper log information (if available), actual survey data (if possible), actual tubular configuration, actual fracture and pore pressures, and actual hardware configuration.

Closed-Loop Cementing technology extends the use of computer programs to operational aspects of all the cementing sequences and reflects a benchmark step towards automating the hydraulics of cementing programs and coupling that information with other wellbore behavior.25 Case study extending CBHP MPD to Cementing Operations This case study brief is an example of extending CBHP MPDs proven ability to deal with drilling hazards associated with narrow and/or relatively unknown drilling margins to also apply to cementing operations. In this example, the primary purpose of Closed-Loop Cementing is to maintain the equivalent circulating density (ECD) within a very narrow margin during cementing operations. The subject well is an extended reach development well to be drilled from a production platform and intended to be an oil producer targeting the Balder Massive Sand, a lower Paleocene turbidities reservoir of the North Sea. The operators previous attempts to access the reservoir with conventional methods were unsuccessful due to encountering a total loss scenario.

The operator had successfully implemented MPD technology on a previous North Sea well which otherwise would have presented significant challenges to conventional drilling methods due to very narrow drilling margins. Encouraged by this experience, the CBHP variation of MPD was chosen to drill the 12 and 8 sections of the subject well in order to keep the EMW between 11.8 and 12.5ppg (at well TD).

The ECD limits for the subject well were based on the wellbore stability of the shale mudstone and the facture gradient of the sand reservoir. This narrow a drilling margin had indicated to the operator that conventional drilling techniques are not practicable or even do-able in this case due to the high ECD generated in the extended reach well profile and depletion of the reservoir which has lowered the fracture gradient. CBHP MPD overcomes this challenge by using a lower mud weight and by managing the downhole pressure using the combined effects of ECD and surface back pressure (SBP). This is possible by using a Rotating Control Device (RCD), MPD choke manifold and other associated equipment to create a closed loop system at surface and provide greater control of the wellbore pressure.

The static mud weight of 10.8ppg for the 12 section and 10.0ppg for the 8 section is comfortably overbalanced compared to the expected reservoir pressure of 8.6ppg. However, the static mud weight is below the well stability limit. Therefore ECD or SBP is required at all times in order to maintain an appropriate wellbore pressure. For tripping operations, the planned strategy for a bit change or BHA failure was to use a heavy mud cap at a suitable depth to balance the well without SBP, allowing removal of the RCD bearing assembly. At TD of both sections, the plan was to displace from drilling mud to low rheology WARP mud, enabling subsequent operations to be completed within the ECD limits.

A well control incident is considered very unlikely with the planned mud weights, but the operator wanted to avoid any change in bottomhole pressure (BHP) resulting from an automatic response by the MPD system. As a result, the systems automatic response to kicks or losses was disabled to focus on the primary objective of keeping bottom hole pressure within a narrow range.

The design of the well was a whipstock sidetrack from the existing 13-3/8 casing at 6,850ft MDBRT (measured depth below rotary table) with a planned 12 section length of 7,672ft down to a depth of 14,672ft MDBRT. The risk of testing the formation boundaries in this case was significant, as having the drill string getting stuck at the lower limit or fracturing the formation at the higher limit created concern for formation testing.

A consequence of using MPD with a lower mud weight for liner running and cementing operations, a new cementing program was developed using SBP applied by MPD to minimize BHP fluctuations throughout the sequence of operations. This involved discrete phases of circulation with different fluids using mud pumps and the cement unit. Due to the complex nature of the operation, MPD requirements were modeled in advance and SBP

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values were calculated to produce a series of manual inputs for each step in the program.

Being an ERD well it was recognized that the ECD at the previous casing shoe will be higher than the ECD at the TD (bottom hole) of the well. As it was for drilling the open hole, this abnormality was factored into the closed-loop cementing operations. The operator requested to focus on maintaining the casing shoe pressure in the 12.10 12.30 ppge range during cementing sequences. The operation was completed successfully by adjusting the dynamic SBP in sync with the density and circulating rates of the spacer, lead and tail slurry cement mixtures, enabling the casing shoe ECD (CS ECD) to consistently be within the desired range as illustrated in Figure 5. The relationship between pump strokes and applications of surface backpressure (SBP) and resulting bottom hole and casing shoe ECDs are illustrated in Figure 6.

Figure5:IllustratestheMPDpressureregimewhiledisplacingcementlead&tailslurryat200gpmwithlinerat14,515measureddepthbelowrotarytable(MDBRT).

StrokesBHECD(ppg)

DynamicSBP(psi) CSECD(ppg)

Spacer

0 11.90 210 12.14200 11.90 210 12.13400 11.85 200 12.10600 11.85 200 12.10800 11.85 200 12.12

LeadSlurry

1000 11.81 190 12.101200 11.80 190 12.111400 11.80 190 12.131600 11.80 190 12.16

11.70

11.80

11.90

12.00

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12.20

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190

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pg

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DynamicSBP(psi) BHECD(ppg) CSECD(ppg)

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1800 11.80 190 12.192000 11.76 180 12.21

TailSlurry2200 11.76 180 12.222400 11.76 180 12.27

Figure 6: Illustrates the relationship between pump rates (strokes), bottomhole ECD, Casing shoe ECD, and dynamic surface backpressure applications for all three cementing phases.

Proven benefits of Closed-Loop Cementing Applying MPD principals to cementing operations is a technology still in infancy. All applications to date have been facilitated by the fact the MPD kit was already on the rig for other drilling-related purposes. In most cases, the MPD kit was used for a singular purpose during the otherwise conventional cementing programas per the kit is aboard, it should help us accomplish this specific objective with our cementing program, so lets try it. Examples of using the technology for such singular purposes include; apply back pressure to keep plugs in place while pulling out of cement, maintain pressure on the well while setting a cement retainer with cement to be placed behind, and for maintaining the ECD within a desired very narrow range at a critical high ECD point in an extended reach well. Collectively, the following features have been proven and documented in some form or fashion:

CBHP MPD techniques when drilling the open hole to be cased & cemented; o Provides less wellbore destabilization by avoiding kick-loss scenarios when drilling in narrow or

previously unknown mud weight windows. o Enables keeping the ECD more constant at a critical point, e.g., casing shoe, bottom hole, etc.,

and within a targeted range indicated by hydraulic flow modeling and other considerations. o Conducting frequent dynamic FITs, for assurance there are no unsuspected weak zones or

natural fractures, allowing time for making adjustments to the cementing program. o Via use of a mass flow meter downstream the MPD choke manifold, effectiveness of cuttings

removal is quantified in real-time for comparisons to conventional methods of determining if and when the wellbore has been cleared of cuttings.

o Via use of a gas chromatograph in the MPD choke manifold system during per-cementing circulation to provide assurance the hole has been circulated free of gas in excess of background levels.

o Quantify the effectiveness of loss circulation material (LCM) which may have been used to control losses.

o Ability to drill deeper open holes in troublesome formations may allow a more favorable/stable formation to the reached for a setting casing.

o HPHT wells often require additional casing strings to compensate for the uncertainty in the pore pressure and fracture pressure predictions. The ability to quantify both with dynamic FITs and dynamic LOTs may allow for eliminating a casing string, removing a potential leak point from the well construction program.

o Quantifying ballooning and breathing with real-time information aids in determining when its time to set casing.

Casing running; o Optimize casing running speeds for comparison with results of hydraulics software for predicting

casing running speeds. Cementing;

o Via monitoring the precise flow rates in-out, immediate detection of an induced fracture during pre-flush, spacer and slurry displacement sequences.

o Maintain a more consistent BHP during cementing operations. o Apply surface backpressure on the annulus to keep plugs & cement retainers in place, improving

chances of achieving the desired top of cement (TOC). o Monitor when spacers, lead & tail slurries turns the corner and enters the open hole annulus. o Apply surface backpressure on the annulus during displacement and/or post cement-placement. o Allows surface backpressure to be applied when pulling out of cement to avoid dislodging cement

wiper plugs from swab pressures when pulling out of cement.

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o Using the MPD kit to test the integrity of the casing shoe in lieu of a cement pump and exercising the BOP.4

Yet-to be proven benefits of Closed-Loop Cementing Much of the vision for the potential for Closed-Loop Cementing on HPHT wells has yet to be proven with practical field applications. Here are several examples:

Field measurements by C. E. Cooke in 1983 concluded that surface pressure applied to the annulus may not reach the desired depth depending on cement properties such as gel strength development. The study also concluded that applying surface pressure by pumping into the top of the annulus should be considered only for well control purposes such as controlling a kick in the annulus.7,8 However, it is hypothesized that by applying modest dynamic surface backpressure with a closed-loop system in the short time before the slurry begins to gain static gel strength (SGS) sufficient to decay hydrostatic pressure, the risk of influx and initiating channeling may be reduced by discouraging influx during this period of time. Lead slurry is designed so that the gel strength development and thickening time are longer than for the tail slurry. The optimum amounts of surface backpressure required for each before the lead and tail cement has acquired their initial sets are proposed to be determined by cementing simulating models and other considerations unique to the objectives of the cementing program. This method may be uniquely applicable to light weight slurries, which tend to possess less density near the top of cement in the annulus where there is less hydrostatic pressure.1 This closed-loop cementing method may also be applicable to post cementing operations. The basis for this logic is cited in API Standard 65 (4.10.1) Post Cementing Operations - Cases for Applying Surface Pressure - Some specialized operations such as foam cementing operations may require that pressure be held on the annulus during WOC time. Job-specific procedures should be consulted to determine a pressure and time schedule for the annulus.1

The aforementioned SPE paper by Cooke, et al also mentions that in spite of the uncertainty in transmitting hydrostatic pressure through unset cement to compensate for hydrostatic head pressure losses, applying small amounts of surface pressure in the form of controlled pressure pulses of low frequency has worked in some wells to help prevent annular flows.14,15

Applicable to floating rigs experiencing wave heave, it is suspected that by closing the MPD choke after displacement and before the initial set would allow the pressure fluctuations created by the drill string heaving with the rig to provide the controlled pressure pulses of suitable magnitude and frequency to be effective in maintaining hydrostatic pressure at or above the formation pressure until the cement has acquired its initial set. The range in controlled pressure excursions will be less than without choke control, resulting in less volume change magnitudes during the initial stages of slurry set. This may result in better bonding at casing and rock interfaces, and less likelihood of gas bubbles entering the slurry at the low pressure point of a pressure cycle.24, 25

Applications of surface backpressure with the MPD kit after cementing has potential to be beneficial in case of a leaking or faulty float or other downhole mechanical barriers in the cementing string.

At this juncture, the authors are not proposing either of the above yet to be proven extensions of Closed-Loop Cementing concepts. However, the size of the prize would indicate further study or field trial may be warranted.

Summary - Closed-Loop Cementing in relation to API Standard 65 - Part 2 Below is an item by item summary of how Closed-Loop Cementing technology facilitates industry best practices for cementing operations. The phrases in italics are key requirements for a successful cementing job as defined by API Standard 65 - Part 2.

A stable wellbore - no gains or losses - Optimize MW, flow rates using CBHP MPD tools & technology, conduct frequent dynamic FITs drilling the open hole. Proper mud conditioning and hole cleaning prior to cementing - Better understanding of margins between PP/FG & EMWs - more efficient hole prep.

SPE/IADC 163452 15

Spacer Design - Use info to adjust density/rheology as necessary to manage ECD, improve displacement of mud, etc Proper fluid dynamics during circulation and placement of cement to achieve mud removal - Real-time flow in/out measurements, apply desired amounts of surface backpressure, maintain the most appropriate flow rate to optimize mud removal within Pp/Fp margins. Tripping requirements - Manage surge/swab. Drilling techniques - Data acquisition that can be applied to subsequent casing running and cementing. Well monitoring - DAQ in real-time, onsite & offsite monitoring. Sustained hydrostatic pressure during cement curing - Without exercising rigs BOP & compensating for heave induced pressure fluctuations.

MPD has demonstrated for decades on land wells that its root concepts and enabling equipment has a most commendable well control track record.9,10 Today, the technology has earned the prognosis that as offshore wells become more challenging to drill and the water depths deeper,it will be required on a growing number of offshore prospects in the future, including those deemed un-drillable otherwise. This prognosis is based on MPDs proven ability to overcome a litany of conventional drilling challenges with enhanced control of the well and more precise ECD management. Closed-Loop Cementing is at the present considered only a fringe benefit of drilling with MPDs closed-loop systems. However, for its ability to improve the chances of getting a cement job done right the first time and serviceable for the life of the well, Closed-Loop Cementing technology has potential to be considered a primary reason for having the kit aboard in the first place on wells that typically present formidable challenges to conventional cementing methods. References API Standard 65, Part 2 Isolating Potential Flow Zones During Well Construction IADC UBO/MPD Glossary of Terms SPE textbook Advanced Drilling & Well Construction, MPD section Hannegan/Moore, Applying MPD Principals to Cementing Operations, Drilling & Completing Trouble Zones Forum, Galveston, October 25, 2012 Hannegan, D., Closed-loop Cementing & Dynamic FITs, presented to US DOI Bureau of Safety & Environmental Enforcement (BSEE), New Orleans, January 23, 2012 Moore, D., Managed Pressure Drilling from a DP Drillship, presented to the US DOI Bureau of Safety & Environmental Enforcement (BSEE), New Orleans, January 23, 2012 Cooke, C.E., Kluck, M.P. and Medrano, R., Field Measurements of Annular Pressure and Temperature During Primary Cementing, paper SPE 11206 published in JPT, pp.1429-1439, August 1983. Cooke, C.E., Kluck, M.P. and Medrano, R., Annular Pressure and Temperature Measurements Diagnose Cementing Operations, paper SPE 11416 published in JPT, pp.2181-2186, December 1984. Skalle, P. and Podio, A.L., Trends extracted from 800 Gulf Coast blowouts during 1960-1996, paper SPE/ IADC 39354 presented at the 1998 IADC/SPE Drilling Conference in Dallas, Texas, 3 - 6 March. Jablonowski, C. J., Podio, University of Texas Center for Petroleum Asset Risk Management (CPARM), The Impact of Rotating Control Devices for MPD and the Incidence of Blowouts, SPE 133019, presented at 2010 SPE Trinidad & Tobago Energy Resources Conference, Port of Spain, Trinidad, 27-30 June 2010. Gao, E., Estensen, O., MacDonald, C., and Castle, S., Critical Requirements for Successful Fluid Engineering in HPHT Wells: Modeling Tools, Design Procedures & Bottom Hole Pressure Management in the

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Field, paper SPE 50581 presented at the 1998 SPE European Petroleum Conference, The Hague, The Netherlands, 20 - 22 October. Adams, N., Causes of Underground Blowouts, article in the January 2006 issue of World Oil, vol.227 no.1. Pritchard, D., Roye, J., Espinoze-Gala, L., Real-time data offers critical tool to redefine well control, safety, IADC Drilling Contractor, November/December, 2012, p.96. Stein, D., Griffin, T.J., Dusterhoft, D., Cement Pulsation Reduces Remedial Cementing Costs, article Published in GasTIPS, 2003 winter issue. Available for downloading from the GTI website link: http:// www.gastechnology.org/webroot/downloads/en/4ReportsPubs/4_7GasTips/Winter03/ WellCompletions_CementPulsationReducesRemedialCementing.pdf. Lang, K., Production Optimization: Pulsation improves cementing results, article in Hart's E&P, March 2003. http://boemre.gov/glossary/index.htm Wessel, M., and B. A. Tarr, Underground well control: The key to drilling low-kick-tolerance wells safely and economically," SPE Drilling Engineering, December 1991, p. 250. Nadeau, P. H., Lessons Learned from the Golden Zone Concept for Understanding Overpressure Development, and Drilling Safety in Energy Exploration, Deepwater Horizon Study Group 3 Working Paper January 2011 Arnone, M., Hannegan, D., Grayson, B., The Mass Balance Technique of MPD, Reaching the Drilling Objectives Safely and Successfully Beyond the Conventional Limits of HPHT Deepwater Wells, OTC Brazil 22242, Rio de Janerio, 4-6 October 2011. Hannegan, D., Advanced Drilling & Well Construction, Managed Pressure Drilling (MPD) chapter, SPE Textbook Series, Richardson: Society of Petroleum Engineers, 2009. Smith, K., MPD helps Make Problems Disappear, IADC Drilling Contractor, 2006. Thorogood, J., Automation in Drilling: future evolution and lessons learned from aviation, SPE 151257, presented at IADC/SPE Drilling Conference, 6-8 March 2012. Hannegan, D., HPHT Wells Challenge Conventional Wisdom, Presented at World Oil HPHT Conference, Houston, 29-30 September, 2010. Gray, K. E., Podnos, E., and Becker, E., Finite-Element Studies of Near-Wellbore Region During Cementing Operations: Part I, SPE Drilling and Production, March 2009, pg.127. Gray, K.E. (2012), Wider Windows Research Program, The University of Texas at Austin.26. rilling & Completing Trouble Zones Forum,27. 28. Hannegan, D., Arnone, M., Dynamic FITs verify changing integrity of complex wellbores, IADC Drilling Contractor, November/December, 2012, p.72.