Recent Advances in Oil and Gas Production Engineering The first semester of 2016-2017 Professor Xianlin Ma School of Petroleum Engineering Xi’an Shiyou University

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

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

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?

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

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

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

Effect of thickness on well PI

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

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

Summations of PIF Distributions

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

Reduce Coning Problem

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

Increased Connectivity: Faults

Increased Connectivity: Layered Reservoirs

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

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

A Comparison of Horizontal Well Costs for Prudhoe Bay, Alaska

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

Applications of Horizontal Wells

Multilateral Well Configurations

Multilateral Well Configurations

Multilateral Well Configurations

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

Multi-Stage Completions

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

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

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

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

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

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

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)

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

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

Hydraulic fractures in horizontal wellbores Goal is create surface area

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

Ideal vs. Non-Ideal Hydraulic Fractures

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

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

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

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

Horizontal Well Completion: Screens

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

Horizontal Well Completion: Gravel Packers

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

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

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

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

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

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.

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)

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).

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

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)

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)

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 0.0001 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

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

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