Horizontal & Extended Reach Wells

PgDip/MSc Energy Energy Programme/Drilling Programme/Drilling Technology Technology

Horizontal Horizontal and Extended Extended Reach Wells Wells

Horizontal & Extended Reach Wells Review

This topic begins by discussing the application of horizontal wells, conventional conventional low angle and horizontal drill string design and horizontal hole cleaning. It introduces the technological technological aspects of extended reach drilling and covers the definition, history, current market application, and implementation implementation of this technology and the application of extended reach drilling in today’s market. The topic concludes by taking a brief glimpse at the future of extended reach drilling.

Content Horizontal Well Applications Increased Formation Exposure One of the main reasons for considering a horizontal well is the increased formation exposure it can provide (Figure 1). Tight f ormations (those with low permeability) permeability) or heavy oil reservoirs may not be economically feasible to produce with a vertical well due to the low production rates normally associated associated with these reservoirs. A horizontal well can improve the economics considerably considerably by exposing more wellbore to the formation. An excellent candidate candidate for a horizontal well well is the thin bed formation (Figure (Figure 2) Figure 1. Increased Formation Exposure of Horizontal Well.

Figure 2. Use of Horizontal Well in Thin Bed Formation.

© The Robert Gordon University 2002

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Reduction in Water and Gas Coning Most oil bearing strata contain water below the oil and/or gas above the oil zone. Normally, water and gas are avoided when a well is completed. However, after a time water and gas may migrate into the wellbore along with the oil being produced. produced. This is normally the result of a phenomenon phenomenon called coning. The oil/water contact zone in the area of the well has risen in a cone shape around the wellbore. The mirror image occurs at the gas/oil transition zone. (Figure 3). The net result of coning is a reduced or chokedoff producing zone around the wellbore. A horizontal well tends to reduce the incidence of water and gas coning. Horizontal wells usually have a lower draw down pressure, compared to a vertical well at the same production rate, which discourages the formation of a water or gas cone. Figure 3. Reduction in Water or Gas Coning in a Horizontal Well.

Figure 4. Intersection of Vertical Fractures by a Horizontal Well.

Intersection of Vertically Fractured Reservoirs. Limestone and dolomite formations can be significant reservoirs. Many of these reservoirs tend to have low porosity and permeability, permeability, which limit their commercial viability when considering a vertical well. These calciferous formations are brittle and often geological forces produce numerous fractures in the formation. These fractures tend to be in the vertical plane, and are difficult for a vertical well to intersect, but ideal for intersection by a horizontal well (Figure 4). Examples of this type of formation are the Austin Chalk of South South Texas, the Rospo Rospo Mare of Italy and the Batu Raja Raja of Indonesia. Indonesia. Although shales shales are not usually usually classified as reservoir reservoir formations, formations, there are vertically vertically fractured shale formations that have been productive due to the horizontal drilling. drilling. An example of this type formation f ormation is the Balken Shale in North Dakota.

EOR (Enhance Oil Recovery) Horizontal wells can improve the efficiency of EOR techniques. The long formation exposure is better suited to introducing steam or water into a zone.


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Drill String Design The drill string, which includes all tubulars from the kelly to the bit, has three primary functions: •

To transmit hydraulics to the bit;

•

To transmit torsional loads to the bit;

•

To transmit tensile and compressive loads to the bit.

Only compressive loading for bit weight is discussed here. Conventional Low Angle Drill String Design

Sinusoidal Buckling In conventional low angle drill string design, all the tubulars used for weight application are located at the bottom of the drill string. The number of drill collars and/or Hevi-Wate required for a desired bit weight is determined by first calculating the air weight of the BHA. At no time is the drill pipe allowed to be used for compression, the neutral point must always be in the drill collars or Hevi-Wate (Figure 5). This is due to the fact that the drill pipe will buckle sinusoidally under very low compressive loads in a vertical hole as calculated by the formula below. This formula was developed developed by Arthur Lubinski in 1950. The compressive load at which sinusoidal buckling occurs is called the critical buckling load. Fc

=

1.94.3 EIp 2

where: Fc = critical buckling load (lbs) 6

E = modulus of elasticity (30 x 10 for steel) 4

I = moment of Inertia (in ) p = buoyed weight per inch of the tubular (Ibs) For 4-1/2" Grade E, Premium Class drill pipe with a nominal weight of 16.60 Ibs/ft used in a vertical well with 10lb/gal mud, the critical sinusoidal buckling load in a vertical hole is 1098 pounds. Sinusoidal buckling means the drill pipe will wrap itself around the inside of the well, taking the shape of a coil spring. Sinusoidal Sinusoidal buckling of the drill pipe during rotary drilling can very quickly lead to fatigue failure, so it must always be located below the top of the collars or Hevi-Wate for this type of drill string.


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Figure 5. Neutral Point in Drillstring in Vertical and Horizontal Wells.

Horizontal Drill String Design Sinusoidal Buckling In the horizontal well, having the weight components as the lowest most element of the drill string is useless. If the well is horizontal, the weight of these elements cannot be used to apply weight to the bit, but only increase the load that must be pushed along the low side of the hole as drilling progresses. A better scenario is to move the collars and Hevi-Wate up the string into the vertical or low angle section of the well, and use something light, like drill pipe, to transmit the compressive loads created to the bit. Figure 5 illustrates the differences between the drill strings used in vertical holes and horizontal wells. It is possible to compressively load drill pipe to quite a large extent in horizontal holes. The limit, or critical buckling load, for inclined wells can be determined by solving the equation below. This equation was developed by Exxon (Dawson et al. 1984) Fc

=

2

EI.p sin θ r

where: 6

E = Modulus of Elasticity (30x 10 for steel) I = Moment of Inertia p = Buoyed weight per inch of the tubular θ

= hole inclination


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r = (actual hole diameter - minimum tubular diameter)/2 where the minimum tubular diameter may be: •

Drill collar OD;

•

Drill pipe tube OD;

•

Hevi-Wate centre upset OD.

For 4-1/2" Grade E, Premium Class drill pipe with a nominal weight of 16.60 Ibs/ft used in an 8-1/2" hole with a 90° inclination and 10 Ib/gal mud, the critical sinusoidal buckling load in a vertical hole is 18,737 pounds.

Helical Buckling It is important to note that the sinusoidal buckling described described above is the limit while rotary drilling due to fatigue failure caused high levels of cyclic stress. If drill string rotation is not present, exceeding the sinusoidal buckling load will generally not create drill string problems. As is often the case when sliding in a horizontal well, very large compressive loads are applied just to get the string to start sliding. In some cases, even using the entire weight of the drill string, sliding/oriented drilling was very difficult, or even impossible. In 1989, a second order of buckling was defined called Helical Buckling. Helical buckling is the square root of 2 times greater than sinusoidal sinusoidal buckling. What helical buckling does does is to cause c ause the drill string to get into a ‘lock up’ condition in the horizontal section of the well, and thus not allow sliding to occur.

Torque and Drag Torque and drag effect can be significant even at moderate overbalances in permeable permeable formations. Most companies provide computational models that have the ability to analyse the expected torque and drag characteristics of well bores, including both sinusoidal and helical buckling. In any new situation, this analysis should be done to ensure that the drill string can accomplish the desired drilling objective without failing due to tension, torsional stress, or buckling.

Horizontal Hole Cleaning High angle wells create special problems when planning the mud system. The main objective is to drill a well with minimum formation damage, clean of drilled cuttings, and completed as planned as economically as possible. To accomplish this, the well design and mud properties for low and high angle wells are somewhat different. There are four major areas that need to be considered. •

Drilling fluid type;

•

Pressure Design;

•

Fluid Flow Design;

•

Drill String Rotation.

Drilling Fluid Type Drilling fluids perform numerous functions when drilling any type of well. Some of these functions include: •

Cooling and lubricating the bit, drill string and other tools;

•

Stabilising sensitive fformations; ormations;

•

Balancing formation pressure;

•

Minimising formation damage;


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•

Cleaning the wellbore of drilled cuttings;

•

Suspending drilled cuttings when circulation stops;

•

Powering downhole motors and provide transmission medium for MWD tools.

These considerations are required for vertical, directional, and horizontal wells with different emphasis depending depending on the type of well drilled. Vertical and low angle directional wells with inclination angles angles less than 45 degrees usually use the same design factors while wells drilled at angles over 45 degrees require different considerations, considerations, especially with regard to hole cleaning and drilled cuttings transport. Suspension of solids becomes critical and much more difficult in highly inclined well bores when circulation is stopped. The cuttings will tend to fall relative to the fluid environment and can build build up on the low side of the well bore. This can lead to stuck pipe and sometimes formation fracturing, in severe cases. This effect can be reduced by maximising the suspension properties properties of the drilling fluid. Fluid loss must also be controlled to reduce the build-up of wall cake which could lead to problems with differential sticking.

Extended Reach Wells Extended-Reach Extended-Reach Drilling (ERD) has evolved from simple directional drilling to horizontal, lateral, and multi-lateral step-outs. ERD employs both directional and horizontal drilling techniques and has the ability to achieve horizontal well departures and total vertical depth-to-deviation depth-to-deviation ratios beyond the conventional conventional experience of a particular field. Extended reach wells started to be recognised as a technology category in the very early 1980's. Prior to this period the term high angle drilling was used. There are several definitions of what an extended reach well is, but a generally agreed definition is a well with a horizontal displacement more than twice the vertical displacement. Current wells have achieved reach to TVD ratios of over 4. After an initial build most wells are drilled with a constant sail angle. Typically sail angles are in excess of 70 or 80° and may incorporate a horizontal section in the pay. There are two factors which dominate the design of ERD wells, torque and drag and hole cleaning, though some would consider these problems as interrelated as they are both highly dependant on drilling fluid properties. Of these drag is probably the most important as it sets the limit for casing setting. Most ERD trajectories are only finalised after extensive torque and drag studies. These are generally based on the 'soft string' model (Johancsik1983). Recent work has indicated that there may be some benefit in increasing the build rate in stages. This method of increasing the build rare in s everal steps reduces near surface doglegs and thus reduces torque and drag. It is also usual for any steering to be undertaken by only sliding for part of a joint and the return to the rotary mode. This reduces the 'tortuosity' of the well. Tortuosity is the planned curvature minus sum of all the curvature increments in the section divided by the footage f ootage drilled. The fluid effects of lubricity and cuttings carrying capacity are also closely controlled. In general oil or synthetic based fluids give better lubricity than water based and are thus the preferred choice for most high angle and ERD wells as they give lower friction factors. Friction factors are a composite function of the materials involved (pipe to formation and/or pipe to casing) and the lubricity of the mud. Some predicted and field data are given on Figure 6. Cutting transport is a function f unction of inclination and velocity as depicted in Figure 7. In all wells the desire is to eliminate bed formation by maximising annular velocity and pipe rotation. Some guidelines guidelines for flowrate, pill size and number of circulations circulations for cleaning are given in Tables 1-3.


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Figure 6. Measured and Predicted Friction Factors.

Figure 7. Effect of Inclination and Velocity on Transport of Cuttings.

As is the case with horizontal horizontal wells wells the ability to survey and steer the well accurately is of prime importance. Presently drilling practices for these wells are ahead of effective completion technologies technologies that allow for reliable low cost maintenance, maintenance, which restricts their utility. Casing wear may also be a problem that needs to be addressed and compensated for.


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Table 1.

Hole size

Flowrates

inches

GPM

17-1/2

1100-1400

12-1/4

950-1400

8-1/2

500

Table 2.

Hole size inches

Pill sizes for hole cleaning BBLS

17-1/2

50+

12-1/4

30-50

8-1/2

20

Table 3. Number of Circulations Required.

Inclination

Hole size (inches) 17-1/2

12-1/4

8-1/2

0-10

1.5

1.3

1.3

10-30

1.7

1.4

1.4

30-60

2.5

1.8

1.6

60+

3.0

2.0

1.7

Principals of Extended Reach Drilling (ERD) ERD Milestone Achievements: The technique has been very successful at drilling shallow ultra ERD wells at 5,500ft TVD: •

2 x 10km+ wells at BP (Wytch Farm) 1998, 1999;

•

1 x 10km+ well drilled by Total (Ara) 1999;

Many operators have pushed the ERD Limit at 9-10,000ft TVD: •

Phillips (Xijiang) - 8km, Norsk Hydro (Oseberg) - 7.8km;

•

Woodside (Goodwyn) – 8.3km, Statoil (Sleipner) - 7.4km;

•

BP (Amberjack) - 6.8km, BP (Niakuk) - 6.0km, BP (Pompano) - 5.6km;

Fewer operators drilled highly deviated wells at 13-15,000ft TVD: •

BP (Gyda) - 6.8km, HMDC (Hibernia) - 6.1km, BP (Yacheng) – 6.0km;

Very few operators drilled deviated wells at >20,000ft TVD: •

Shell (Auger) - 3.9km.


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Figure 8.

Figure 9. Extended Reach Drilling E volution.


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Table 4. Top 20 ERD Wells (Correct as of May 2003).

Top Twenty ERD Wells Horizontal

Rank

Displacement (ft)

Measured Depth (ft)

TVD (ft)

Operator

Well

Location

1

35,196

37,001

5371

BP

M-16Z

UK, Wytch Farm

2

34,728

36,693

5436

Total

Ara CN-1

Argentina

3

33,182 33,1 82

34,967

5266

BP

M-11

UK, Wytch Farm

1

31,441

31,441

Lone Star

Bertha Rogers1

USA, Oklahoma

4 5

29,324

31,355

5889

BP

M-14

UK, Wytch Farm

6

27,250

30,439

9501

Woodsid e

Goodwyn GWA-18

Australia

7

26,840

28,501

4914

Total

Kaus CS-1

Argentina

7188

RWEDEA

Mittelplate D5

Germany

9554

Phillips

Xijiang 243

South China Sea

Cerf Ranch 1-9

USA, Pecos Co. TX

M-05

UK, Wytch Farm

8 9

26,725 26,446

29,511 30,308

10

29,670

29,670

1

Hunt Energy

11

26361

28593

5285

BP

12

26,138

29,173

5358

BP

M-15

UK, Wytch Farm

13

25,764

30,600

NA

Norsk Hydro

30/6 C-26

North Sea

14

25,195

26,880

4932

Total

Kaus CS-2

Argentina

15

25,108

27,241

NA

BP

M-09

UK, Wytch Farm Denmark

16

25,081 25, 081

29,631

7074

Maersk

Dan MFF19C

17

24,839

27,450

6798

RWEDEA

Mittelplate D4

Germany

18

24,823 24,8 23

28,497

9340

Phillips

Xijiang 243 A-17

China China Germany

19

24,649 24,6 49

28,250

9287

Phillips

Xijiang 243 A-18

20

24,590

27,178

6752

RWEDEA

Mittelplate D3


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Figure 10. Current Market Place.

Figure 11. Shallow versus Deep ERD Wells.


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ER Projects Typically Break Into Four Groups: •

Small rig ERD;

•

Very shallow ERD;

•

Ultra-long ERD;

•

Deep water ERD.

Figure 12. Current Marketplace Well Profiles.

Figure 13. ERD Development Types.


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What was once considered the envelope of ERD now only indicates the difference between standard and advanced technology. This envelope is being continuously enlarged, as technology technology boundaries are broken. Figure 14. Comparison of Extended Reach Wells.

Deep Water and ERD Projects •

•

•

Current limitations in deep water for ERD wells are ~1,200-4,000 ft Water Depth, ~2,000 ft BML with total Step-out Step-out Ratios of 2.5:1 being well within comfort envelope. Typically 15-21,000 ft Departure and 6,000 ft TVD; Such projects are using ERD technologies technologies to minimise facilities, eliminate subsea tiebacks and develop multiple fields from the same SPAR. The current depth limitation is 5,400 ft of water with wells to the horizontal; Here the large capacity rigs are available, the limitations are in the down hole equipment and technologies.

Key Challenges Key challenges for ERD in any environment are: •

Equivalent Equivalent circulating densities (ECD’s);

•

Shallow directional control;

•

Hole cleaning (ER and riser ECD’s);

•

Fit-for-purpose practices now change and have a different set of priorities.

Application of ERD Applications •

•

•

Extending life of mature fields by kicking off from old wells (producers / injectors); Controlling Controlling the environmental environmental impact of drilling activity ie, eliminate drilling/production drilling/production islands in sensitive areas (W ytch Farm, Alaska); Allows access to reserves in environmenta environmentally lly sensitive areas areas from small footprint footprint locations;

•

Permits satellite field developments from existing platforms;

•

Increased production by staying in the payzone laterally;


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•


Reduction in the number of platforms, surface locations and subsea completions and total wells required to exploit fully a hydrocarbon reservoir.

Benefits •

Allows economic economic access to reserves; reserves;

•

Fewer pipelines and satellite production– reduction in costly subsea equipment;

•

Brings production forward;

•

•

Allows re-assessment re-assessment of opportunities opportunities previously previously thought thought uneconomic; uneconomic; Plan new bespoke ERD developments.

Figure 15. Typical Oil Production Increases from Field ERD Development.

Extended Reach Complexity This is defined by: •

Well design (HD/TVD, complexity, etc.);

•

Water depth;

•

Rig capabilities;

•

Hole sizes and depths;

•

Drilling fluid type and properties;

•

Lithology factors;

•

Location (logistics);

•

Directional drilling strategy;

•

Rig site practices.


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Figure 16. ERD Complexity Index.

Limitations Constraints to successful ERD Include: •

•

Excessive torque and drag (Conventional drilling tools are prone to twist-off); Applying weight weight to the drill drill bit gives less than than optimal WOB transfer; transfer;

•

Poor hole cleaning in long, high-angle hole sections;

•

Possible buckling of casing or drill string;

•

Running casing successfully to the bottom of the well;

•

Guiding a wellbore accurately through the pay zone;

•

Topside power packages less than fit for purpose;

•

•

Prohibitive well costs due to the required trajectory and the resulting drilling rig specifications; Less than optimal directional control, particularly critical on some of the complex reservoirs;

•

Environmental considerations;

•

Wellbore instability.

Figure 17. ERD Technical Boundaries.


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Tension may be a primary concern in vertical wells, but in ERD, torsion may be the limiting factor. Running normal-weight drill pipe to apply weight to the bit in ERD can lead to buckling of the drill pipe and rapid failure.

Future Developments in ERD Figure 18. Pushing the ERD Envelope. Future ERD Opportunities

The next step will be to push the drilling technology boundary boundary and overcome the technical challenges in completions and interventions, where wellbore, workovers and maintenance will be critical. The future for GeoSteering GeoSteering technology and rotary steerable s teerable tools is bright. Currently, Currently, these steerable systems are used primarily on relatively expensive extended-reach wells where they can provide a technical capability beyond the limit of standard motor-driven motor-driven systems. Here, these systems can be run economically even if their cost is high. Further work will focus on increasing their reliability, reliability, upward telemetry systems and operating times while cutting costs. Today’s bottlenecks represent the toughest challenges: •

ECD’s;

•

Ultra deep casing runs;

•

Practices – design and implementation.

ECD (Equivalent Circulating Circulating Density) remains one of the big challenges in pushing the drilling envelope: •

Initiatives have been taken to research low ECD drilling fluids.

Casing Challenges: •

Push down with rotation and circulation is the next step;

•

The limit in using top drive weight has almost been reached;

•

The possibility of the combination of pushing and rotational forces increasing the probability probability of getting casing or liners successfully to TD. These have casing and connection design implications;


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•


As greater force is used, unanticipated unanticipated forces are being being applied to to the casing string that increase the possibility of its failure.

Casing Deployed Logging: •

•

A current joint project with a major operator operator leads leads to the development development of a special special composite eccentric shoe joint to house the logging tools; The shoe joint required the development of a ‘de-centraliser’ that compensated for hole size and orientation to allow formation contact necessary for proper logging tool readings;

•

Obtains true open hole logging results;

•

Saves on logging and wiper trips;

•

All drillable. drillable.

Under Balanced Drilling: •

Improves hole cleaning;

•

Increases ROP;

•

Lowers or eliminates formation damage;

•

Eliminates differential differential sticking of drill string;

•

Is compatible with coiled tubing or conventional drilling techniques.

Expandable Tubulars: •

The ability to go deeper with fewer diameter decreases, and taking this to the ultimate: - monobore to TD.

Steerable / Drillable Liners: •

Partnerships are required to merge steering technology into the existing capabilities.

Subsurface Models: •

The large-scale, 3-D subsurface visualisations and models;

•

Well planning with all contingencies modelled and mapped in advance;

•

Real-time updates of the models with LWD, to aid decision-making.

How ERD Drilling Research & Development Adds Value: •

Helps define the limits of what’s possible;

•

Helps identify and manage risks;

•

Provides predictive models for optimisation;

•

Visualisation to aid understanding;

•

Simulation – ‘Learning before Doing’;

•

Improved products and practices;

•

Casing / liner drilling systems;

•

Lighter / stronger drillpipe;

•

Expandable tubulars;


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•

ECD reduction methods;

•

Combinations of emerging technologies;

•

Improved ‘real-time’ modelling;

•

Intelligent completions.

•

Summary – Getting ERD Right:

•

Same as ‘conventional’ drilling – only different;

•

Requires attention to detail at all stages;

•

Need to identify and manage key risks;


•

Appropriate Appropriate use of technology technology helps; helps;

•

Need to refine models with real data;

•

Need to get it right first time - often difficult to recover from hole problems; problems;

•

Teamwork is crucial.


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Horizontal & Extended Reach Wells

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