1. Recent Advances in Oil and Gas Production Engineering
The first semester of
Professor Xianlin Ma
School of Petroleum Engineering
Xi’an Shiyou University

2. Course Contents: Chapter 1 Introduction
Chapter 2 Gas Well Unloading Technologies
Chapter 3 Advanced Hydraulic Fracturing Technologies
Chapter 4 Horizontal Well Fracturing
Chapter 5 Coiled Tubing Operations and Intelligent Well
Chapter 6 Unconventional Oil and Gas Production
Chapter 7 Shale Gas Development

3. Horizontal Well Fracturing
Outline
4.1 Introduction
4.2 Horizontal well completion
4.3 Multi-stage multi-cluster fracturing
4.4 Open-hole fracturing technologies
4.5 Cased-hole fracturing technologies

4. Selecting Horizontal vs. Vertical Wells
Can vertical wells be stimulated effectively?
Can vertical wells drain the reservoir (contact the required volume)?
Can vertical infill wells be drilled economically?
Can field development economics be improved by switching to horizontals?

5. Main sections of horizontal well
Horizontal drilling is the process of steering a drill bit to follow horizontal path oriented approximately 90° from vertical through the reservoir rock
Vertical section
Kick-off point
First build section
Radius of curvature
Second build section
Horizontal section

6. Applications of Horizontal Well
Increased exposure to the reservoir
Connect laterally discontinuous features
Reservoirs that may have potential water/gas-coning problems
Tight reservoirs (permeability << 1 millidarcies) 
Natural vertically fractured reservoirs
Economically inaccessible reservoirs
Heavy oil reservoirs
Coal bed methane reservoirs
Thin reservoirs
Layered reservoirs with high dip angle

7. Horizontal well + hydraulic fracturing
Drill horizontally Fracture the formation Compartmentalize the lateral(横向)
Maximum
Reservoir
Contact

8. Effect of thickness on well PI

9. Productivity Improvement Factor
Productivity Index:
PI = qhc / p
where
qhc: hydrocarbon flow rate
Dp: drawdown, Dp= pre – pwf
Productivity Improvement Factor:
PIF = PIH /PIV
PIV = Productivity Index of vertical well
PIH = Productivity Index of horizontal well

10. World Horizontal Well Look Back: 1980 - 1995 SPE 30745
Summarized the experiences of horizontal well development from 230 fields all over the world
Categorized field into three types: conventional, heavy oil and fractured
Evaluated the successful rate of horizontal well technology by PIF
Emphasized there is an error-bar in any performance prediction: reserve estimated and data that models depend on

11. Summations of PIF Distributions

12. Increase Reserves per Well
Usually 2-4x that of vertical well:
Examples
Andrew Field- 4x
Santa Rosa field, Venezuela. 1.7x
Hemiar field, Masila block, Yemen, 4x
Prudhoe Bay, Alaska, 1.8x

13. Reduce Coning Problem

14. Increased Connectivity: Natural Fractures
Horizontal wells have been used to intersect fractures and drain them

15. Increased Connectivity: Faults

16. Increased Connectivity: Layered Reservoirs

17. EOR application
A long horizontal well provides a large reservoir contact area and therefore enhances injectivity of an injection well

18. Concerns Associated with Horizontal Well
More demanding of drilling and completion technology
Requires highly trained personnel
Options for monitoring, control and intervention limited at present
Costs 20% higher

19. A Comparison of Horizontal Well Costs for Prudhoe Bay, Alaska

20. Horizontal Well Costs Use of good equipment expensive
Use of well trained and capable personnel
Intervention, may need to re-enter well later in life to set plugs, open sliding sleeves...
Artificial lift may be required as water cut increases
Stimulation costs are much higher than vertical wells

21. Applications of Horizontal Wells

22. Multilateral Well Configurations

23. Multilateral Well Configurations

24. Multilateral Well Configurations

25. Horizontal Well Completion
Open Hole
Screens/pre-packed screens
Gravel packers
Slotted/perforated liners
Cemented/perforated

26. Multi-Stage Completions

27. Selection of Horizontal Well Completion/Stimulation Method
Know the reservoir
Deliverability(kv, kh, Pi,GLR)
Stress field magnitude and orientation
Drainage area shape and size
Define the well
Maximum possible length
Limitations on orientation
Expected skin damage
Options for completion
Cased/cemented; open-hole; uncemented liner

28. Horizontal Well Completion: Open Hole
utilized in competent, stable formations
rocks are generally quite competent and consolidated in low-permeability reservoirs

29. Horizontal Well Completion: Slotted Liners
(a) single inline (b) multiple inline (c) single staged (d) multiple staged
less stable formations
prevent formation collapse near the wellbore
difficulty to effectively isolate and stimulate zones

30. Perforating in open hole completion
The creation of perforations with a jetting tool results in very effective flow paths from the open hole into the formation
A small jetting tool is used to create small cavities
additional fluid is pumped to initiate a small hydraulic fracture
Jetted perforation tunnels have less damage than conventional shape-charge perforations

31. Zone isolation in open hole completion
the installation of formation packers at strategic locations for zone isolation
Open-Hole completion with mechanical diversion

32. Multiple transverse fractures
Thick reservoirs
Long Xf possible
Compartmentalized reservoirs
Linear reservoir flow
Difficult and expensive to place in desired locations

33. How many transverse fractures?
Best well performance requires multiple, orthogonal fractures
The best outcome is a 3000 ft lateral with 15 stages set 400 ft apart (xperm = yperm)

34. Longitudinal fractures
Thin reservoirs
low kv/kh in thick reservoirs
Better when effective Xf is low
Better in continuous reservoir
Large volume treatments
Easy to place and pump effectively

35. Direction of Fracture Growth
Controlled by in-situ stress field
Magnitude of all three principal stresses
Principal stress axis
Degree of overpressure or depletion
Direction of well (azimuth)
Deviation of well from vertical

36. Hydraulic fractures in horizontal wellbores
Goal is create surface area

37. Multi-stage: Open-Hole Fracturing
Hydraulic pressure is equal between packer elements
Fracture propagation through weakest formation
Less pressure required to fracture formation
Localized fractures still contribute to production

38. Ideal vs. Non-Ideal Hydraulic Fractures

39. Multi-stage: Open-Hole Fracturing
Two approaches
Use of liners with sleeve ports separated by packers
Controlling packers & ports is initiated by multi-diameter balls

40. Openhole sleeve completion
Consists of ported sliding sleeves between openhole packers and an anchor or anchor packer(s)

41. Cemented sleeve systems
Cemented sleeves require graduated sized balls, and sleeves may be single entry or multiple entry
Stop stage-to-stage communication across the packer sealing element in the lateral
Reduce breakdown and frac propagation occurred at the packer element/formation face interface

42. Coiled tubing frac sleeves
consist of running a sleeve designed to accept a “shifting tool” run on coiled tubing to open the sleeve and are usually run in cemented laterals

43. Horizontal Well Completion: Screens

44. Screens Use with gravel pack or stand alone
Popular in horizontal completions
Not strong support to the borehole

45. Horizontal Well Completion: Gravel Packers

46. Horizontal Well Completion: Cemented Liner
Cementing（固井）a well is a reliable method for controlling fracture placement in horizontal wells
A cased and cemented horizontal section allows fracture initiation points to be controlled in order to place multiple hydraulic fractures
more expensive

47. Example: Barnett shale lateral showing cemented casing design and perforation plan

48. Unified fracture design
Treatment sizes can be unified by dimensionless proppant number
The dimensionless number determines the theoretically optimum fracture dimensions at which the maximum productivity index can be obtained.
rapid analytical method for achieving the optimal fracture geometry

49. Dimensionless productivity Index with fracing
The primary goal of well stimulation is to increase productivity of a well by
removing damage near wellbore or by
superimposing a highly conductive path onto the formation
Dimensionless productivity index in pseudo-steady state
Equivalent wellbore radius
Pseudo-skin concept

50. Well-fracture-reservoir system
A fully penetrating vertical fracture in a pay layer of thickness h
Penetration ratio in the x direction
Dimensionless fracture
conductivity

51. Proppant number -1
Fracture penetration and the dimensionless fracture conductivity (through width) are competing for the same resource: propped volume.
Once the reservoir and proppant properties and the amount of proppant are fixed, one has to make the optimal compromise between width and length.
The available propped volume puts a constraint on the two dimensionless numbers.

52. Proppant number -2 Dimensionless proppant number (Nprop)
Vprop is the propped volume in the pay
(two wings, including void space between the proppant grains)
Vres is the drainage volume
(i.e., drainage area multiplied by pay thickness)

53. Proppant number -3
Most important parameter in unified fracture design is Nprop
Nprop is weighted ratio of propped fracture volume (two wings) to reservoir volume, with a weighting factor of two times the proppant-to-formation permeability contrast.
Only the proppant that reaches the pay layer is counted in the propped volume.
For instance, the fracture height is three times the net pay thickness, then Vprop can be estimated as the packed volume of injected proppant divided by three (volumetric proppant efficiency).

54. Dimensionless productivity index with Ix as a parameter
Dimensionless productivity index as a function of dimensionless fracture conductivity, with Ix as a parameter
Not very helpful in solving an optimization problem involving a fixed amount of proppant

55. Dimensionless productivity index with Nprop as a parameter
Dimensionless productivity index as a function of dimensionless fracture conductivity, with proppant number as a parameter (for Nprop < 0.1)

56. Dimensionless productivity index with Nprop as a parameter
Dimensionless productivity index as a function of dimensionless fracture conductivity, with proppant number as a parameter (for Nprop > 0.1)

57. Dimensionless productivity index with Nprop as a parameter
The best compromise between length and width is achieved at dimensionless fracture conductivity located under the peaks of the individual curves
For Nprop < 0.1, the optimal compromise occurs always at CfD = 1.6
For frac & pack treatments, typical Nprop is between and 0.01.
For medium to high permeability formations (above 50md), CfD = 1.6
In tight gas reservoirs, it is possible to achieve large Nprop but difficult

58. OPTIMUM FRACTURE CONDUCTIVITY (Nprop < 0.1)
Vf = w ∙ h ∙ xf
( = Vprop / 2 )
The most important implication of the above results is that there is no theoretical difference between low and high permeability fracturing.
In all cases, there exists a physically optimal fracture that should have a CfD near unity.
In low permeability formations, this requirement results in a long and narrow fracture
in high permeability formations, a short and wide fracture provides the same dimensionless conductivity

59. Design logic
Assume a volumetric proppant efficiency and determine the proppant number
Use figures (or rather the design spreadsheet) to calculate JDmax and also CfDopt from the proppant number
Calculate the optimum fracture half-length
Calculate optimum averaged propped fracture width