2010-3-10_Optimal Horizontal Wellbore Design for Artificial Lift

8/12/2019 2010-3-10_Optimal Horizontal Wellbore Design for Artificial Lift

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Artificial Lift - Closed Discussion Item

Optimal Horizontal Wellbore Design for Artificial Lift

Posted Wednesday, March 10, 2010 17:11 by Bresee, Don K

We are going to be drilling horizontal gas wells about 1800 meters deep. I am looking for advice on how to drill andcomplete these wellbores so that we can unload these wells if needed. We are looking at possibly 4.5" casing fromsurface. Typically we would run 2.375" tubing. Does anyone have advice on where to land tubing, how to build degrees inthe wellbore (quick build versus slow), and where would be the max build we could run a plunger from (I have heard arange of 40 to 60 degrees). For this formation reservoir pressure is typically around 16MPa at initial completion and permis around 4 mD. Typical production from these wells could be around 3 mmcfd and around 1-5 bbl/mmcf of liquidproduction (about 30% condensate and 70% water) Any advice on this would be great, thanks.


Posted Thursday, March 11, 2010 7:45 by White, Jason A View Attachment(s)

These are all good questions and some that we have been trying to answer in the Eagle Ford here in Texas. We are inthe early stages of developing this field and are still trying different methods of drilling, completion and production. Weare also still working on artificial lift selection but will most likely be utilizing plunger lift in wells with an acceptableliquid yield and gas lift in wells with a high liquid yield. One of the issues we are working on now is toe-up vs. toe-downlaterals. Our fluid is a retrograde condensate. Our wells are around 12,000 deep with 5,000 laterals. We have 4 , 5,5 and 7 casing all typically with 4 liners in the horizontal. We have liquid yields of 75 to 300 BBL/MMscf in the

wells we have been producing with lots of water during initial production (from completion operations) which tapers offfairly rapidly. Our gas rates are similar to yours. We have 2 7/8 and 2 3/8 tubing installed with the end of tubing setanywhere from just above deviation to mid-lateral. We will be installing 2 3/8 tubing on the upcoming wells which willall have 5 casing to surface and plan to set the end of tubing just above the top perforation in the lateral (this will bejust past the heel). Most of the upcoming wells are toe up and the thinking is that the liquid will collect in the heel andcan be removed if the tubing is set there. The X-Nipple will be set at around 45 o for possible plunger lifting and apacker will not be run (unless gas lift will be utilized). This also gives flexibility to flow up the casing/tubing annulusearly in the life of the well if production rates are high. It is important to make sure that the dog-leg severity (DLS) isnot too high to run a plunger. The attached spreadsheet was provided by a vendor and can be used to calculate themaximum DLS that a plunger in tubing can pass through (it is just based on geometry.) In theory a plunger should beable to fall to 60o but the recommendations we have received are to not go much below 45 o. Once the plunger starts

getting into the higher deviations it significantly slows down and time to reach bottom is increased (if it reaches thebumper spring at all). Slickline work at this angle is also an issue. On the tubing that is run deep into the lateral, asliding sleeve is installed in between two X-Nipples located at about 45 o inclination. The thought process behindrunning tubing deep into the lateral is to reduce the flow area to increase velocity to keep the lateral swept of liquidwhich will minimize back-pressure on the reservoir and also keep liquid from sitting in the lateral and potentially causingdamage from relative permeability affects. The nipples and sliding sleeve provide a means to control how the productionfrom the lateral flows. If the sleeve is closed then production will travel down the liner/tubing annulus to the end oftubing and then up the tubing to surface. If the sleeve is open then production can flow up the liner/tubing annulus andtubing to the sleeve and then up the tubing to surface. If the sleeve is open and a plug is installed in the X-Nipple belowthe sleeve then the tubing in the lateral serves as a dead string and the production flows up the liner/tubing annulus tothe sliding sleeve and then up the tubing to surface. Of course, you can always flow up the casing/tubing annulus to

surface if a packer is not installed. I have attached some simple sketches to show some of the flow possibilities. All ofour wells have dual flow hook-up on surface to allow production from tubing and/or casing/tubing annulus. We havealso done quite a bit of modeling to look at liquid hold-up in the horizontal based on the various tubing setting depths,sizes and flow path scenarios (we have been using PipeSim and Hysys; both are compositional which is important forour retrograde condensate). A couple of the issues with running the tubing into the lateral is that you typically dontknow where production is coming from along the lateral (unless a production log is run prior to running tubing) and ifthe well is proppant fractured you run the risk of getting the tubing stuck if proppant flows back into the well andaround the tubing (remember we would have about a mile of tubing in the horizontal). Also, at the rates we are

d l k l k h l l f b d h l l l f

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removed with the plunger (this is inefficient). Our thinking is that given the depth of our wells the plunger fall time ishigh any liquid that has collected in the tubing (not only at the bottom but also along the tubing string to surface) willfall to bottom and even be pushed to bottom as the plunger falls. The lateral has a large volume and basically infinitepermeability which will enable fluid to fall out of tubing much faster than in a vertical well. Extra care must be taken bythe Operators to ensure wells dont load up with the bumper spring. We are not running relief valves since the currentspring design does not allow much liquid accumulation. We are discussing with one of the vendors about possiblyinstalling a stiffer spring which would allow more liquid accumulation. I have also attached a little information onstanding valves from Ferguson-Beauregard. Build rate has been limited to 6o/100 on the most recent wells inanticipation of rod pumping in the future. In discussions with internal experts this was the recommended build angle toensure the rod pump could be placed close to the heel and minimize rod and tubing wear. However, with the type offluid we are trying to pump, the likelihood that rod pump will be used in the future is low. Also, with high build anglesthe drillers are able to lower the kick-off point and make contact with more of the formation with the same laterallength. The lower kick-off point lowers the point where the nipples can be set (based on 45 o) and also allows packersto be set lower (if they are run for gas lift). The vertical height between the nipple and the heel is reduced to anacceptable level with the current build rate of around 12o/100. You will want to make sure that coiled tubing

intervention and tubing can effectively be run in whatever build angles/DLS you end up with. One issue that you mightlook at with 4 casing is the ability to run side-pocket gas lift mandrels. With your low liquid yield you might not beinterested in gas lift, but with 4 casing you would have to run conventional gas lift valves and pull the hole tubingstring to make adjustments or repair valves. Please give me a call if you would like to discuss. I would be interested inhearing your thoughts and what all you have considered.


Posted Thursday, March 11, 2010 8:44 by Slemko, Gord View Attachment(s)

Don, Attached are course abstracts for a couple of Petroskills Horizontal Well Design courses being brought in-house toCalgary. They are being offered the first 2 weeks of May. Contact Sheila Reader for more info if they appeal to you.


Posted Friday, March 12, 2010 9:33 by Busse, Greg

Don, We have not yet reached the point yet were we see a lot of vertical well loading in our horizontal wells in Wolf.But, we are presently working on a horizontal well in Wolf that has not performed up to expectations and requires aplunger lift on it. So I am interested to here Jason's response, Thanks for the posting the question. Our originalthoughts on artificial lift were very similar to Jason's email we set up with profile nipple at ~45deg, in hopes that forartificial lift we would utilize plunger. Here are our experiences so far with this well: Early this year, we performed acoil-tubing drill-out of the horizontal leg and then re-snubbed in tubing. The original slickstring we had was just 2 3/8"hung to ~175 m above formation (the


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rod pumping, less angle is better, 8 is max 6 is ok 5 or less is better. I think our plunger team is starting to look atdeviated well fall times, which are long in our S wells. Dave Martin (Farmington) is a contact for that effort.


Posted Wednesday, March 17, 2010 15:17 by Hannaman, Bart View Attachment(s)

Don, I have been doing a lot of work recently in the Eagle Ford related to flow in the horizontal section of both a Toeup and a toe down horizontal. I have attached a presentation that I am currently working on. My work is not done yet,however I think that it highlights many of the artificial lift design issues as well as flow characteristics during the freeflow stage. The hold up (Pipe Volume % taken up by liquid) left in the lateral and the expected horizontal angles (2degrees up or down) are tailored to the Eagle Ford fluid, so this same analysis may need to be carried out in your areafor quantitative results. HYSYS was used to analyze the hold up values due to the complicated fluid composition. Thispresentation should however give a qualitative picture of issues being faced while unloading a horizontal well. Notethat we have a light condensate so do not take the hydrostatic gradients used in this presentation to your areas. Makesure to view the presentation with the notes page showing. I have hidden slide 20-22 they only apply to the EagleFord fluid and represent volume changes in liquid due to phase change at different pressures, this may not be an issuein your area. I would appreciate any comments or concerns regarding the presentation since it is not yet completed, Istill have time to make modifications before I present it. Also, has anyone been trying continuous soap as an artificiallift in horizontals? I have no experience with it in horizontals, however it may provide the ability to flow the wellsabove critical rates longer before shut ins are required and we may be able to inject soap deeper than we can plungerlift. I have talked to a vendor and he has experience running 2205 stainless caps to 90 degrees depending on DLS.With a more robust cap we may be able to get even deeper.


Posted Thursday, March 18, 2010 14:11 by Jaeger, Mark A.

There really aren't too many reservoirs that allow an 'ideal' wellbore construction from a flow/unloading perspective,but a low heel and lower DLS (~5 deg/100ft) typically make a nicer horizontal wellbore. If there is room and nomajor scaling concerns, you could land a sliding sleeve just below the profile nipple (@45 to 60 degrees) and have atailpipe below both of those to the heel all with a cap string to tubing tail. That way you could produce in threestages: free flow, soaped flow, and plunger lift (the first two stages being with the sleeve closed). Its more jewleryand more cost, but maybe in an ideal world it could happen. Of course the poor man's alternative would omit thecap sting and sleeve, still set a longer tubing string and then perf tubing below the profile nipple when the timecame for plunger lift. Just some more ideas.


Posted Monday, March 22, 2010 10:38 by Watts, Jeff T

There is not enough clearance between 2-3/8" tubing and 4-1/2" casing to make an outside cut, complicating fishingoperations. Have you considered 5" casing?

Page 3 of 3Ask the Network


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Top View of RV Housing

Bottom View of RV Housing

Lip that the Seat fits against

Slots milled in ID of housing

(flow path)


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Ball

Seat

Spring

Top view of finished RV

Spring will compress

against V-Pack

mandrel, and holdthe seat in the UP

position.

Internals of RV

Bottom view of finished RV


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Seat is against the inner

lip (red text on page 1),and there is no flow

around seat

Seat: in the UP position

(no pressure differential)

Seat: in the down position(pressure differential greater that 22psi)

Ball (not pictured), pushes

seat down, and exposes

slots (blue text on page 1).Water/flow is allowed to

bypass around the seat

until the differential is less

then 22 psi, then spring

force seat back up.


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Plunger Type Part No.

1-1/2" Viper PLS1500S 1.5 9.5 1.61

2-1/16" Viper PLS1700S 1.641 10 1.7512-3/8" Viper (1.89) PLS2000S 1.89 12 1.995

2-3/8" Viper (1.87) PLS2000SS 1.875 12 1.995

2-7/8" Viper PLS2500S 2.34 11.875 2.441

1-1/4" Sidewinder PLS1250SW 1.265 6.5 1.38


2-3/8" Mini-Viper PLS2000MV 1.89 7.75 1.995

2-3/8" Single Pad PLP2000S 1.86 7.25 1.995

2-3/8" Dual Pad PLP2000 1.86 12.375 1.995

2-3/8" One-Two Pad PLPA2000 1.735 11.375 1.995

2-7/8" Single Pad PLP2500 2.31 7.25 2.441

2-7/8" Dual Pad PLP2500 2.31 12.375 2.441

Plunger Type Part No.

1-1/2" Viper PLS1500S 1.5 9.5 1.516

2 1/16" Vi PLS1700S 1 641 10 1 657

Plunger O.D. atWidest part

Top and

Bottom (in.)

Plunger Contact

Length

Reference

Tubing Dia.= Drift

Diameter

Plunger Contact

Length

Reference

Tubing Dia.=

Nominal

Diameter

Well Master Plungers in Deviated Wells

Enter values in blue columns. All other values arecalculated.

Plunger O.D. at

Widest part

Top and

Bottom (in.)


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2-3/8" Mini-Viper PLS2000MV 1.89 7.75 1.901

2-3/8" Single Pad PLP2000S 1.86 7.25 1.901

2-3/8" Dual Pad PLP2000 1.86 12.375 1.901

2-3/8" One-Two Pad PLPA2000 1.735 11.375 1.901

2-7/8" Single Pad PLP2500 2.31 7.25 2.3472-7/8" Dual Pad PLP2500 2.31 12.375 2.347


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46.5 123.3 4.75 0.22 87.34819583 4.755092 102.7768

41.9 136.6 5 0.22 87.48061071 5.004838 113.856427.8 206.0 6 0.21 87.99546597 6.003674 171.6386

31.8 180.3 6 0.24 87.70938996 6.004798 150.24

27.3 209.7 5.9375 0.202 88.05148879 5.940935 174.7263

103.5 55.4 3.25 0.23 85.95197065 3.258128 46.15391

66.6 86.1 3.875 0.21 86.89797285 3.880686 71.71298

66.6 86.1 3.875 0.21 86.89797285 3.880686 71.71298

97.6 58.7 3.625 0.27 85.74031778 3.635041 48.93898

33.6 170.5 6.1875 0.27 87.50140561 6.193388 142.0669

76.1 75.3 5.6875 0.52 84.7760524 5.711222 62.72703

94.7 60.5 3.625 0.262 85.86608639 3.634456 50.41706

32.6 175.7 6.1875 0.262 87.57534834 6.193045 146.3886

6.8 846.1 4.75 0.032 89.61401322 4.750108 705.1101

6 1 937 5 5 0 032 89 63331202 5 000102 781 282

MaximumRecommended

Deviation

(degrees/100 ft )

Equivalent Minimum

Radius of Tubing

Curvature (ft)

Maximum

Recommended

Deviation

(degrees/100 ft )

Equivalent Minimum

Radius of Tubing

Curvature (ft)

Half

Plunger

length (AP)

Maximum

Clearance

(2x drift-pl

dia) (PC) Angle OCA

Chord

Length

(AC)

Radius of

Curvature


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7.0 819.1 3.875 0.022 89.67471133 3.875062 682.5504

7.0 819.1 3.875 0.022 89.67471133 3.875062 682.5504

29.8 192.4 3.625 0.082 88.70415095 3.625927 160.3335

10.2 560.4 6.1875 0.082 89.24073068 6.188043 466.9741

48.8 117.3 5.6875 0.332 86.65922867 5.697182 97.7647

26.9 213.2 3.625 0.074 88.83053824 3.625755 177.659.2 620.9 6.1875 0.074 89.31479829 6.187942 517.441


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55.74781 123.3322 46.45651

50.3229 136.6276 41.9357533.38167 205.9663 27.81806

38.1362 180.288 31.78017

32.79176 209.6715 27.32647

124.1408 55.3847 103.4507

79.89604 86.05557 66.58003

79.89604 86.05557 66.58003

117.0761 58.72678 97.56338

40.33018 170.4803 33.60848

91.34153 75.27244 76.11794

113.6437 60.50047 94.70311

39.13956 175.6663 32.6163

8.125798 846.1321 6.771499

7 333566 937 5384 6 111305

Deviation

in

degreees

per 100'

Radius

with 20%

Safety

Factor

Deviation

with 20%

Safety

Factor


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8.394373 819.0605 6.995311

8.394373 819.0605 6.995311

35.7354 192.4002 29.7795

12.26959 560.369 10.22466

58.60584 117.3176 48.8382

32.25208 213.18 26.8767311.07292 620.9292 9.227434


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Horizontal and Multilateral Wells: Analysis and Design

Discipline: Reservoir Engineering Level: Advanced Primary Instructor(s):

Dr. Ding ZhuDr. A. Daniel HillDr. J.M. Peden

DESIGNED FOR

Geologists, reservoir engineers, production and completion engineers, and development, asset,and project managers

YOU WILL LEARN HOW TO

Identify the applications of horizontal, multilateral, and intelligent wells from geologicaland reservoir aspects

Determine optimum well locations and their placement in reservoir structures

Assess multidisciplinary inputs for successful screening of advanced well projects

Select the most appropriate well geometries to enhance production rates andhydrocarbon recovery from a variety of reservoir types and lithologies

Predict horizontal and multilateral well productivity with integrated reservoir flow and wellflow models

Evaluate formation damage and well completion effects on advanced well performances

Diagnosis problems in advanced wells and conduct the necessary sensitivity analyses

Assess reservoir management requirements and how to achieve these through

developing well design criteria to achieve life of a well success

Minimize technical and economic risk in advanced well projects

ABOUT THE COURSE

The course is designed as a companion course to Horizontal and Multilateral Wells: Drilling and


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Horizontal and Multilateral Wells - Analysis and Design_HML1_long_8_20_08.doc

process, the technical and economic assessment of risks and uncertainties, and the provision offlexible solutions.

The application and benefits of horizontal and multilateral wells are analyzed. The process ofcandidate screening and selection, involving geological, reservoir, and production characteristicsare considered, as well as constraints on drilling and completion options. Learn to selectappropriate well geometries or trajectories, with respect to a range of reservoir environments, tooptimize well capacity and fluid recovery.

Methods to predict well performance and recovery from horizontal and multilateral wells arepresented. The integration of inflow and wellbore flow performance for individual and multilateralwells is discussed. Well completion options for horizontal and multilateral wells are summarized.Reservoir simulation approach is presented during the course.

Economic and risk analysis and well performance prediction for advanced well applications aresummarized with a number of case histories, serving to highlight the performance and benefits ofhorizontal wells and the elements of risk and uncertainty at the initial design stage. One personalcomputer is provided, at additional cost, for each two participants.

COURSE CONTENT

Technical and economic benefits of advanced well systems

Limitations and risk

Reservoir applications for various well types

The screening of applications for advanced well applications

Geological structure characteristics

Classification of advanced wells

Reservoir flow and geometrical issues

Impact and importance of reservoir description

Reservoir inflow performance at different boundary conditions

Wellbore flow and integrated well performance

Commingled production and cross flow in multilateral wells

Formation damage in horizontal and multilateral wells

Well completion and combined effect of completion and damage on well performance

Reservoir simulation considerations


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EXAMPLESThe instructor will like to use the examples from participants field cases for analysis in the classas demonstration exercises. Field problems will be analyzed and suggestions will be providedthrough the course.

About the Instructor(s):

DR. DING ZHU is an Assistant Professor of the Petroleum Engineering Department of TexasA&M University and General Partner and Consultant for EHZY Engineering. She holds a B.S.degree in mechanical engineering from Beijing University of Science & Technology, and M.S. andPh.D. degrees from The University of Texas at Austin in petroleum engineering. Dr. Zhu hasworked at the University of Texas as a Research Scientist for 11 years before she joined Texas

A&M University. She is an expert in the areas of production engineering, well stimulation(acidizing and fracturing), and complex well production (horizontal, multilateral and intelligentwells). She has consulted on multilateral well design and optimization, well stimulation and other

production projects for companies around the world. For the past ten years, she has taught shortcourses on production engineering topics in the US, Mexico, Venezuela, Brazil, and China. Dr.Zhu is author of about forty technical papers and is currently co-authoring a book on MultilateralWells that will be published by the Society of Petroleum Engineers (SPE). She is a member of theSPE Production Monitoring and Control Committee.

DR. A. DANIEL HILLis Professor of Petroleum Engineering and holder of the Robert Whiting

Endowed Chair at Texas A&M University. Previously, he served on the faculty at The Universityof Texas at Austin, where he taught for twenty-two years after spending several years in industry.He holds a B.S. degree from Texas A&M University and M.S. and Ph.D. degrees from TheUniversity of Texas at Austin, all in chemical engineering. He is the author of the SPEmonograph, Production Logging: Theoretical and Interpretive Elements, co-author of thetextbook, Petroleum Production Systems, and author of over eighty technical papers and fivepatents. He has been a SPE Distinguished Lecturer, served on numerous SPE committees andwas founding chairman of the Austin SPE Section. He was named a Distinguished Member ofSPE in 1999. Professor Hill is an expert in the areas of production engineering, well stimulation,

production logging, and complex well performance, and has presented lectures and courses andconsulted on these topics throughout the world.

DR. J. M. PEDEN is Professor of Well Technology at the Department of Petroleum Engineering


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major operating and service companies in areas such as horizontal wells, sand control,multilaterals and other aspects of well design and troubleshooting.

Dr. Pedens principal areas of expertise are in well completion design; formation damage; sandcontrol; and, horizontal and multilateral wells. He has published over 100 technical papers, twotextbooks, and contributed to numerous conferences as a keynote speaker. He has been anactive member of SPE, holding a number of posts including Chairman of the Aberdeen Section in1986/87. In 1999/2000 he was an SPE Distinguished Lecturer on the subject of multilateralwells. He obtained his B.Sc. in Chemical Engineering in 1970, returning to University in 1976from Shell, to obtain his M.Eng. in Petroleum Engineering and was awarded his Ph.D. in 1983.

In-House Course Presentations .

All courses are available for in-house presentation to individual organizations. In-house coursesmay be structured the same as the public versions or tailored to meet your requirements. Specialcourses on virtually any petroleum-related subject can be arranged specifically for in-housepresentation. For further information, contact our In-House Training Coordinator at one of thenumbers listed below.Telephone +1832 426 1200Facsimile +1832 426 1250E-Mail [email protected]

Public Course Presentations .

How to contact PetroSkills Training Inc.

1-800-821-5933 toll-free in North America orTelephone 1-918-828-2500Facsimile 1-918-828-2580E-Mail [email protected] www.petroskills.com

Address P.O. Box 35448, Tulsa, Oklahoma 74153-0448, U.S.A


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Horizontal and Multilateral Wells: Completions and Stimulation

Discipline: Production and Completions Engineering Level: Specialized

Primary Instructor(s):Dr. Ding ZhuDr. Buyon GuoDr. Daniel Hill

DESIGNED FOR

Drilling, completion, production, reservoir, and research engineers; geologists; managers indrilling, completion, production, and exploration; others involved in various phases of horizontaland multilateral wells or interested in gaining an interdisciplinary up-to-date understanding of thiscontinually evolving technology

YOU WILL LEARN HOW TO

Successfully design and optimize horizontal and multilateral wells

Engineer wells, taking into account limitations imposed by well bore stability and borehole

friction Determine the appropriate zonal isolation methods for horizontal and multilateral wells

Design damage removal, stimulation, and workover operations

ABOUT THE COURSE

Are your horizontal and multilateral wells yielding the expected results? Why are some of thesetypes of wells great successes, while others are embarrassing failures? Are you hesitant to

recommend these types of wells for fear they will yield poor results? Too many operators arefinding themselves asking these same questions. Successful multilateral and horizontal wellsrequire new considerations, interdisciplinary planning, and special techniques. This intensecourse addresses the critical need for a proper understanding of all aspects of horizontal andmultilateral well drilling and completion processes that make these wells unique. It is designed forthose planning or working with horizontal and multilateral wells, and interested in effective use ofthe latest technology Basic understanding of important reservoir characteristics hole stability


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Horizontal and Multilateral Wells - Drilling, Completions and Stimulation_HML2_8_20_08.doc

Participants are required to bring a scientific calculator. One personal computer is provided, atadditional cost, for each two participants.

COURSE CONTENT

Introduction to horizontal and multilateral drilling and completions

Rock behavior in highly deviated wells

Reservoir characteristics influencing drilling and completion design

Effects of reservoir heterogeneity Formation damage

Completion types and methods: adaptability to reservoir types and management

Zone isolation

Stimulation and workovers

Borehole trajectories and friction in multilateral and horizontal wells

Special techniques and problems: Drillstrings and workstrings, cuttings removal, coiledtubing, short radius, MWD and geosteering, underbalanced drilling, specific multilateralissues

Casing and liners: design, running, and cementing procedure

About the Instructor(s):

DR. DING ZHU is an Assistant Professor of the Petroleum Engineering Department of TexasA&M University and General Partner and Consultant for EHZY Engineering. She holds a B.S.degree in mechanical engineering from Beijing University of Science & Technology, and M.S. andPh.D. degrees from The University of Texas at Austin in petroleum engineering. Dr. Zhu hasworked at the University of Texas as a Research Scientist for 11 years before she joined Texas

A&M University. She is an expert in the areas of production engineering, well stimulation

(acidizing and fracturing), and complex well production (horizontal, multilateral and intelligentwells). She has consulted on multilateral well design and optimization, well stimulation and otherproduction projects for companies around the world. For the past ten years, she has taught shortcourses on production engineering topics in the US, Mexico, Venezuela, Brazil, and China. Dr.Zhu is author of about forty technical papers and is currently co-authoring a book on MultilateralWells that will be published by the Society of Petroleum Engineers (SPE). She is a member of theSPE Production Monitoring and Control Committee.


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Horizontal and Multilateral Wells - Drilling, Completions and Stimulation_HML2_8_20_08.doc

industry and academia. Guo holds a BS degree from Daqing Petroleum Institute, MS degree fromMontana Tech, and PhD degree from New Mexico Tech, all in Petroleum Engineering.

DR. A. DANIEL HILLis Professor of Petroleum Engineering and holder of the Robert WhitingEndowed Chair at Texas A&M University. Previously, he served on the faculty at The Universityof Texas at Austin, where he taught for twenty-two years after spending several years in industry.He holds a B.S. degree from Texas A&M University and M.S. and Ph.D. degrees from The

University of Texas at Austin, all in chemical engineering. He is the author of the SPEmonograph, Production Logging: Theoretical and Interpretive Elements, co-author of thetextbook, Petroleum Production Systems, and author of over eighty technical papers and fivepatents. He has been a SPE Distinguished Lecturer, served on numerous SPE committees andwas founding chairman of the Austin SPE Section. He was named a Distinguished Member ofSPE in 1999. Professor Hill is an expert in the areas of production engineering, well stimulation,production logging, and complex well performance, and has presented lectures and courses andconsulted on these topics throughout the world.

In-House Course Presentations .

All courses are available for in-house presentation to individual organizations. In-house coursesmay be structured the same as the public versions or tailored to meet your requirements. Specialcourses on virtually any petroleum-related subject can be arranged specifically for in-housepresentation. For further information, contact our In-House Training Coordinator at one of thenumbers listed below.Telephone +1832 426 1200Facsimile +1832 426 1250E-Mail [email protected]

Public Course Presentations .

How to contact PetroSkills Training Inc.

1 800 821 5933 toll free in North America or


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Liquids in a Toe Up vs. Toe

Down Well

Bart

3/11/2010


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3 Modeled Scenarios

Model is set up to run ratescenarios using Hysys outputs

BFT # 1 fluid composition

Current runs are only in 4-1/2

Model output are Volume of hold up in

lateral during flow Volume of liquid left

remaining in lateral duringa shut in and its location

Variable rate entry points

Assumption that in a

flowing state once fluidstream make it to the Tbg itcan be successfullyremoved from the wellbore.


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Pressure Drop in HorizontalPressure Drop Toe to Heel

-50.00

0.00

50.00

100.00

150.00

200.00

250.00

300.00

350.00

400.00

10 100 1000 10000 100000

Surface Rate [Mcffd]

Dp[psi] Toe up DP

Horizontal

Toe down DP

Shaded green area represents the flow rates of concern. Above 300

Mcfd (critical rate 2-3/8 Tbg at 50 psi PTbg). Upper end pressure

drop convergence


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Toe up Example

Evenly distributed inflow from a 2000Mcfd well

20% hold up at the interval closest to the heel and decreases to 16% at

the toe.


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Toe up Flow Variable Rate

constant Pressure


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Horizontal Example


37% hold up at the interval closest to the heel and decreases to 25% at the toe.


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Horizontal Flow Variable Rate

constant Pressure


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Toe Down Example


52% hold up at the interval closest to the heel and decreases to 35% at the toe.


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Toe Down Flow Variable Rate

constant Pressure


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Flowing Summary

Hold up in 4-1/2" at 500Mcfd

0

10

20

30

40

50

60

0 1000 2000 3000 4000

Pressure BH [psi]

Volumeinla

teral[bbl]

Toe up Horizontal Toe Down

Hold up in 4-1/2" at 1000Mcf d

0

10

20

30

40

50

0 1000 2000 3000 4000

Pressure BH [psi]

Volumeinla

teral[bbl]



0

5

10

15

20

25

30

3540

45

0 1000 2000 3000 4000

Pressure BH [psi]

Volumeinlateral[bb

l]



0

10

20

30

40

50

0 1000 2000 3000 4000

Pressure BH [psi]

Volumeinlateral[bb

l]



31/42

SHUT INDoes hold up matter?

With a Toe up well, less liquidis left in the tbg

More left in a Horizontal well

Even more in a Toe down

well

Do we know weather the heel or

the toe is going to be the

better zone before we drill the

well?

Is there a difference in energy

required to unload a toe up

vs. a Toe down after a shut

in?


32/42

Can we change anything by going

Toe up or Toe Down?Hold up in 4-1/2" at 2000 Mcf d

0

2

4

6

8

10

12

0 500 1000 1500 2000 2500 3000 3500

Pressure

Volumeinlateral[bbl]


Hold up in 4-1/2" at 1500 Mcf d

0

2

4

6

8

10

12

0 500 1000 1500 2000 2500 3000 3500

Pressure

Volumeinlateral[bbl]


Hold up in 4-1/2" at 1000 Mcfd

0

2

4

6

8

10

12

0 500 1000 1500 2000 2500 3000 3500

Pressure BH [psi]

Volu

meinlateral[bbl]


Hold up in 4-1/2" at 500 Mcfd

0

2

4

6

8

10

12

0 1000 2000 3000 4000

Pressure BH [psi]

Volu

meinlateral[bbl]


It is not possible to remove all of the liquids from the horizontal section

A toe down well seems to always have twice the perforations covered


33/42

SHUT INDo we know weather the heel or

the toe is going to be the

better zone before we drill the

well?

NO


34/42

SHUT IN

BRING ON

Is there a difference in energy

required to unload a toe up

vs. a Toe down after a shut

in?

Time and thought are

required for how a toe up will

unload in comparison to aToe down

A vertical model is necessary

in order to successfully model

unloading of the horizontal


35/42

Toe Up


36/42

17 bbl of liquid accumulated at

the heal based on the volume ofhold up in the flowing system


37/42

Toe up Bring on after shut in

summary (no volume change considered)

Vertical hei ght of liqu id colum n in Horizontal @ 1000 Mcfd

0.0

1000.0

2000.0

3000.0

4000.0

5000.0

6000.0

7000.0

8000.0

0 1000 2000 3000 4000

Pressure BH [psi]

Liquidcolu

mn

height[ft]

0

500

1000

1500

2000

2500

HydrostaticHead[psi]

Height of Liquid in Tbg Back Pressure

Vertical height o f liqui d column in Horizontal @ 1500 Mcfd

0.0

1000.0

2000.0

3000.0

4000.0

5000.0

6000.0

7000.0

0 1000 2000 3000 4000

Pressure BH [psi]

Liquidcolumn

height[ft]

0

500

1000

1500

2000

2500



Vertical height o f liqui d column in Horizontal @ 2000 Mcfd

0.0

1000.0

2000.0

3000.0

4000.0

5000.0

6000.0

7000.0

0 1000 2000 3000 4000

Pressure BH [psi]

Liquidcolumn

height[ft]

0

200

400

600

800

1000

1200

1400

1600

18002000



Vertical hei ght of liqu id colum n in Horizontal @ 500 Mcfd

0.0

1000.0

2000.0

3000.0

4000.0

5000.0

6000.0

7000.0

8000.0

0 1000 2000 3000 4000

Pressure BH [psi]

Liquidcolumn

height[ft]

0

500

1000

1500

2000

2500

HydrostaticH

ead[psi]



38/42

Toe down Not completed


39/42

Pressure Drop in HorizontalPressure Drop Toe to Heel

-50.00

0.00

50.00

100.00

150.00

200.00

250.00

300.00

350.00

400.00

10 100 1000 10000 100000

Surface Rate [Mcffd]

Dp[psi] Toe up DP

Horizontal

Toe down DP

Shaded green area represents the flow rates of concern. Above 300

Mcfd (critical rate 2-3/8 Tbg at 50 psi PTbg). Upper end pressure

drop convergence


40/42

Tbg Modeling

The Tbg will have some amount of Liquid

Casing pressure is increasing faster than the Tbg and then they become parallel. Theory 1 -The liquid falling down the Tbg can be seen during shut in.

Theory 2 liquids are being pushed from the Csg into the Tbg Can there be liquids in the Csg falling out and being pushed into the tbg?

Theory 3 As pressure increase vapor compresses into a liquid, once at pressurethough it may turn back into a gas partially.

Plunger Cycle Marlene Olson #1

0

50

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300

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400

450

500

4:48:00 7:12:00 9:36:00 12:00:00 14:24:00 16:48:00 19:12:00

Time

Pressure/height

Ptbg

Pcsg

Fliud height


41/42

Liquid increase down hole

White line represent the pressure path and there for the liquidgeneration during a shut in


42/42

500 psi Liquid

2010-3-10_Optimal Horizontal Wellbore Design for Artificial Lift

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Transcript of 2010-3-10_Optimal Horizontal Wellbore Design for Artificial Lift