STATISTICAL ANALYSIS OF SUCKER ROD PUMPING FAILURES IN THE PERMIAN BASIN by ZHANYU GE, B.S.E., M.S.E. A THESIS IN PETROLEUM ENGINEERING Submitted to the Graduate Faculty of Texas Tech University in Partial Fulfillment of the Requirements for the Degree of MASTER OF SCIENCE IN PETROLEUM ENGINEERING /-N Approved ^ May, 1998
170
Embed
STATISTICAL ANALYSIS OF SUCKER ROD PUMPING A THESIS IN ...
This document is posted to help you gain knowledge. Please leave a comment to let me know what you think about it! Share it to your friends and learn new things together.
Transcript
STATISTICAL ANALYSIS OF SUCKER ROD PUMPING
FAILURES IN THE PERMIAN BASIN
by
ZHANYU GE, B.S.E., M.S.E.
A THESIS
IN
PETROLEUM ENGINEERING
Submitted to the Graduate Faculty of Texas Tech University in
Partial Fulfillment of the Requirements for
the Degree of
MASTER OF SCIENCE
IN
PETROLEUM ENGINEERING
/ -N Approved ^
May, 1998
AC /IlG3'/
T 3 ACKNOWLEGDEMENTS
/"^O ' I First I would like to express my sincere gratitude to Dr. Lloyd R. Heinze for his
^ ^f' encouragement, guidance, advice, and financial support to me throughout the whole
process of my writing the thesis and my stay in the Department of Petroleum
Engineering. Without Dr. Heinze's help, I could not have accomplished my study. Dr.
Heinze is the sponsor of the research project of ALEOC. I learned a lot from his attitude
toward academic study, and shared his expertise in drilling, production, and computer
science. I also enjoyed his attitude toward students.
I would like to thank Dr. John J. Day for having been a member of the committee, for
his guidance and advice for my study in all areas, and for his patience to spend time to
correct my thesis.
My deep thanks go to Dr. Herald W. Winkler, Dr. Scott M. Frailey, Dr. Marion D.
Arnold, and Dr. Lome A. Davis for their generosity to let me share their knowledge and
expertise, and for all their warm help during my study.
I am indebted to Mrs. Johnita G. Greer, Mrs. Michelle Doss, Mrs. Ronda Brewer, and
Mr. Joe Mclnerney for all their warm help and support throughout my study in this
department. I thank all the related officers in the Graduate School, especialh' Mrs. Barbi
Dickensheet, for their kind help .
I want to express my gratitude to my classmates Mr. Kenneth Dang, Mr. Anthony
Pol, Mrs. Silvana C. Runyan, Mr. Paulus Adisoemarta and other Big and Small brothers
and sisters in this department for their generous help.
I thank my teachers and colleagues at the University of Petroleum, China for all their
encouragement, help and sacrifice for me. I would like to express deep thanks to my
parents for their efforts to give me life, cultivate me and let me grow up.
I would like to thank my dearest friend, my wife, Huifang Liu for her support to my
study and care for my daily life. My two sons, Wenqi (John) Ge and Wencan (Shawn)
Ge, gave me infinite courage and energy to work hard.
ii
TABLE OF CONTENTS
ACKNOWLEDGEMENTS ii
ABSTRACT vi
LIST OF TABLES ix
LIST OF FIGURES xi
CHAPTER
1. INTRODUCTION 1
2. LITERATURE REVIEW OF DENVER CITY UNIT 6
2.1 Formation Characteristics 10
2.2 Denver Unit History 13
2.2.1 1964-1980 13
2.2.1.1 Project Pattern Evolution 13
2.2.1.2 Production Technology Practices 19
2.2.2 1980-present 30
2.2.2.1 Project Pattern Evolution 30
2.2.2.2 Continuous Area EOR Performance 32
2.2.2.2.1 Injector-To-Producer Conversions 33
2.2.2.2.2 Injection Performance 34
2.2.2.2.3 Gas-Oil-Ratio Trend 35
2.2.2.2.4 CO2 Production 35
2.2.2.2.5 Flowing Wells 37
2.2.2.3 WACO2 Area EOR Performance 37
2.2.2.4 Denver Unit WAG Development 38
2.2.2.5 Recent COj Flood Performance 40
2.2.2.5.1 Continuous Area 40
2.2.2.5.2 WACO2 Area 41
2.2.2.5.3 Final Injection Area 41
2.3 Denver Unit Sucker Rod Pumping Failures 42
111
2.4 Summary 44
3. DATA FROM COMPANIES 45
3.1 Pretreatment of Primary Databases 45
3.1.1 From Access File to Excel File 45
3.1.2 Data Sorting 45
3.1.3 Pretreated Data 46
3.2 Failure Frequencies 46
3.3 Failure Frequency Graphs 80
3.4 Some Observations of the Tables and Graphs 106
3.5 Summary 107 4. APPLICATION OF FAULT TREE ANALYSIS TO
SUCKER ROD PUMPING SYSTEM 108
4.1 Introduction 108
4.2 Definition of Failures 108
4.3 Understanding the System 109
4.4 Construction of the Fault Tree 109
4.5 Evaluation of the Fault Tree 110
4.6 Control of Failures 124
4.7 Summary 125 5. STATISTICAL ANALYSIS OF THE SUCKER ROD
PUMPING FAILURES IN THE PERMIAN BASIN 126
5.1 Introduction 126
5.2 Statistical Mathematics 127
5.2.1 Some Nomenclatures Used in Statistical Analysis 127
5.2.2 Normal Distribution 128
5.2.2.1 Normal Distribution 128
5.2.2.2 Fitting a Normal Distribufion to Observed Data... 130
5.2.3 Sampling Distribution 130
5.2.3.1 Sampling Distribufion of the Mean 131
5.2.3.2 Sampling Distribution of the Variance 132
IV
5.2.4 x^-Distribution 133
5.2.5 t-Distribufion 135
5.2.6 Regression Analysis 136
5.2.6.1 Simple Linear Regression 137
5.2.6.2 Polynomial Regression 138
5.3 Statistical Analysis of the Sucker Rod Pumping Failures in the Permian Basin 139
5.4 Summary 151
6. CONCLUSIONS AND SUGGESTIONS 152
REFERENCES 155
ABSTRACT
This thesis serves the research project. The Artificial Lift Energy Optimization
Consortium (ALEOC), which is supported by 11 oil companies in the Permian Basin.
The objectives of ALEOC are to share successes and failures in production operations
between consortium members, thereby reducing present operating costs, increasing lift
efficiency, extending lower-rate well producing life and increasing oil well profitability.
The first step toward the goal is to analyze the recorded databases to find out the
production operation history and direct the future operations, and hence this thesis. The
Permian Basin is one of the largest oil production areas in the world and sucker rod
pumping is the main kind of artificial lift in that area. Wasson San Andres field is one of
the top old fields and among the most complex in the Permian Basin. Denver City Unit is
the largest of all the units in Wasson field. This thesis has just concentrated on tracing the
history of this unit.
Denver City Unit is operated by Shell Oil Company, it mainly produces oil from the
San Andres formation (4700 to 7300 ft. deep, averaging 5200 ft.). The productive portion
of the San Andres at Denver City Unit is subdivided into First Porosity and Main Pay.
Main Pay possesses the most favorable reservoirs and porosity development. The
discovery well was completed on September 28, 1935. Water flood began just after its
foundafion in 1964, and resulted in the peak production, 150,000 BOPD, in 1975. COj
injection began in mid-1984, and maintained the steady production thereafter. Denver
City Unit Water-Alternating-Gas injection process has the advantages over both
continuous CO2 injection and WAG process. Experience shown that in Denver City Unit
7-in. casing has higher artificial lift efficiency. During the 1980s, the beam pumping units
were mainly API 640's and 456's. The average run time between failures was
approximately 15 months. In recent years sucker rod pumping failures have decreased
gradually.
The data provided by 11 oil companies came from about 25,000 sucker rod pumping
wells, a quarter of the total sucker rod lifted well numbers in the Permian Basin. This is a
VI
big and reliable sample group from the population of sucker rod pumping wells in the
Permian Basin. The databases were first pretreated from Access files or Excel files to the
generalized Excel data file; with data sorting, the data were reorganized according to their
company, field, location, formafion and depth. Failure frequencies for total, pump, rod,
and tubing were calculated to make them more comparable. According to the sorted
failure frequencies, failure frequency plots were made to make them more
straightforward. Observafions of the failure data and plots revealed that different
companies have very different failure frequencies, which is an index of field operation
efficiency, facility manipulation, underground working conditions of the sucker rod
pumping equipment; there is a trend of failure frequency decrease year after year among
the participated companies with a few exceptions.
In this thesis Fault Tree Techniques have been successfully applied to the analysis of
the sucker rod pumping system. After the system was fully understood, a big fault tree
was built from top event to bottom events. The evaluation of the fault tree is in the
reverse direction, from bottom to top. The statistical probability of occurrence of the
events at different levels were calculated. From the analysis of the fault tree structure and
Company A's data, the conclusions are: because of its OR-gate structure, sucker rod
pumping system is liable to suffer failure, any component may result in complete failure
of the whole system; the downhole pump has the highest probability to fail: the weakest
portions of the sucker rod string are polished rod, VA rod body, and 7/8 rod box and pin.
Suggestions are to get deep into the working theories of the whole system; make the
whole system equal-strength during design; find out the failure causes related to
operation, manufacturer, equipment working conditions, and so on.
Traditional statistical techniques are applicable to all kinds of observed data. In this
thesis, the necessary tools have been presented, and used the data for all the companies'
total as an example to show the analysis methods. To do the complete analysis here,
normal distribution, x"-distribution, and t-distribution are needed to compute their means,
variances, and standard deviations. By fitfing the normal (or x'- or t-) distribution to
observed data, we may convert the discrete system to continuous system, and do the
Vll
sampling distribution analysis. Regression analysis is used to relate the dependent
variable to the independent variable(s), and to predict the future occurrence on a
statistical basis. According to the sampling analysis of the failure data from the Permian
Basin, a rough idea about the failure frequencies are: total is 0.66 per well per year,
pump is 0.25 per well per year, rod is 0.22 per well per year, and tubing is 0.16 per well
per year. Due to the incompleteness of the failure data, the main purpose of this part is to
provide the necessary methodology.
Vll l
LIST OF TABLES
1 -1 San Andres Units Data 5
2-1 Summary of the Denver Project Data 16
2-2 Denver Unit Sucker Rod Pumping Failures 43
2-3 Denver Unit Sucker Rod Pumping Failure Frequency 43
3-1 Company A Sucker Rod Pumping Failures in the Permian Basin 47
3-2 Company B Sucker Rod Pumping Failures in the Permian Basin 48
3-3 Company C Sucker Rod Pumping Failures in the Permian Basin 49
3-4 Company D Sucker Rod Pumping Failures in the Permian Basin 50
3-5 Company E Sucker Rod Pumping Failures in the Permian Basin 51
3-6 Company F Sucker Rod Pumping Failures in the Permian Basin 52
3-7 Company G Sucker Rod Pumping Failures in the Permian Basin 53
3-8 Company H Sucker Rod Pumping Failures in the Permian Basin 54
3-9 Company I Sucker Rod Pumping Failures in the Permian Basin 57
3-10 Company J Sucker Rod Pumping Failures in the Permian Basin 58
3-11 Company K Sucker Rod Pumping Failures in the Permian Basin 58
3-12 Company A Sucker Rod Pumping Failure Frequencies in the Permian Basin 59
3-13 Company B Sucker Rod Pumping Failure Frequencies in the Permian Basin 60
3-14 Company C Sucker Rod Pumping Failure Frequencies in the Permian Basin 61
3-15 Company D Sucker Rod Pumping Failure Frequencies in the Permian Basin 62
3-16 Company E Sucker Rod Pumping Failure Frequencies in the Permian Basin 63
3-17 Company F Sucker Rod Pumping Failure Frequencies in the Permian Basin 64
3-18 Company G Sucker Rod Pumping Failure Frequencies in the Permian Basin 65
3-19 Company H Sucker Rod Pumping Failure Frequencies in the Permian Basin 66
3-20 Company I Sucker Rod Pumping Failure Frequencies in the Permian Basin 68
3-21 Company J Sucker Rod Pumping Failure Frequencies in the Permian Basin 69
3-22 Company K Sucker Rod Pumping Failure Frequencies in the Permian Basin 69
IX
3-23 Failure Frequency Of Every Compan> In The Permian Basin 70
3-24 Failure Frequency In Andrews 71
3-25 Failure Frequency In Midland 72
3-26 Failure Frequency In New Mexico 73
3-27 Failure Frequency In Denver 74
3-28 Failure Frequency In Levelland 75
3-29 Failure Frequency In Wasson 76
3-30 Failure Frequency In Monahans 77
3-31 Failure Frequency In MSAU-ANDREWS 78
3-32 Failure Frequency In Sundown 79
4-1 Failure Data Sheet 119
4-2 Failure Frequency Data Sheet 120
4-3 Total Failure Data Sheet 121
5-1 The Cumulative Distribution Function of Standardized Normal Distribution 129
5-2 Average Yearly Failure Frequencies 143
5-3 Coefficients of the Polynomial Regression Matrix 148
5-4 Coefficients of the Polynomial Regression Constant Vector 148
5-5 The Regression Coefficients 149
5-6 Results of Regression Analysis 150
LIST OF FIGURES
1 -1 The Permian Basin 2
I -2 Permian Basin Geological Composition 3
2-1 Location of Wasson Field 6
2-2 Wasson San Andres Field 7
2-3 Wasson Clear Fork Field 8
2-4 Denver Unit Project Pattern 9
2-5 Denver Unit Structure 11
2-6 Subdivision of the San Andres Reservoir 12
2-7 Denver Unit Oil Production 14
2-8 Denver Unit Producfion and EOR History 14
2-9 1964-1980 Project Performance 17
2-10 Original Peripheral Waterflood Patterns 18
2-11 Waterflood Project Status in 1979 19
2-12 CO2 Injection Areas 31
2-13 Denver Unit Production and Injection History 32
2-14 Denver Unit Continuous Area Production Performance History 33
2-15 Denver Unit Continuous Area Oil Cut versus Cumulative Oil Production 34
2-16 Denver Unit Continuous Area Injection History 35
2-17 Denver Unit Continuous Area Hydrocarbon Gas-Oil-Ratio 36
2-18 Denver Unit WACO2 Area Oil Producfion History 39
2-19 Denver Unit WACO2 Area Project Patterns 39
2-20 Recent Injection Status 41
2-21 Recent Oil Production Response for the WACO2 Area 42
2-22 Denver Unit Sucker Rod Failure Frequencies 43
3-1 All Companies Total Failure Frequencies 80
3-2 All Companies Pump Failure Frequencies 81
3-3 All Companies Rod Failure Frequencies 81
3-4 All Companies Tubing Failure Frequencies 82
XI
3-5 Andrews Total Failure Frequencies 82
3-6 Andrews Pump Failure Frequencies 83
3-7 Andrews Rod Failure Frequencies 84
3-8 Andrews Tubing Failure Frequencies 84
3-9 Midland Total Failure Frequencies 85
3-10 Midland Pump Failure Frequencies 85
3-11 Midland Rod Failure Frequencies 86
3-12 Midland Tubing Failure Frequencies 87
3-13 New Mexico Total Failure Frequencies 88
3-14 New Mexico Pump Failure Frequencies 88
3-15 New Mexico Rod Failure Frequencies 89
3-16 New Mexico Tubing Failure Frequencies 89
3-17 Denver Total Failure Frequencies 90
3-18 Denver Pump Failure Frequencies 90
3-19 Denver Rod Failure Frequencies 91
3-20 Denver Tubing Failure Frequencies 91
3-21 Levelland Total Failure Frequencies 92
3-22 Levelland Pump Failure Frequencies 92
3-23 Levelland Rod Failure Frequencies 93
3-24 Levelland Tubing Failure Frequencies 93
3-25 Wasson Total Failure Frequencies 94
3-26 Wasson Pump Failure Frequencies 94
3-27 Wasson Rod Failure Frequencies 95
3-28 Wasson Tubing Failure Frequencies 95
3-29 Monahans Total Failure Frequencies 96
3-30 Monahans Pump Failure Frequencies 96
3-31 Monahans Rod Failure Frequencies 97
3-32 Monahans Tubing Failure Frequencies 97
3-33 MSAU-ANDREWS Total Failure Frequencies 98
3-34 MSAU-ANDREWS Pump Failure Frequencies 98
XII
3-35 MSAU-ANDREWS Rod Failure Frequencies 99
3-36 MSAU-ANDREWS Tubing Failure Frequencies 99
3-37 Sundown Total Failure Frequencies 100
3-38 Sundown Pump Failure Frequencies 100
3-39 Sundown Rod Failure Frequencies 101
3-40 Sundown Tubing Failure Frequencies 101
3-41 Company A Failure Frequencies 102
3-42 Company B Failure Frequencies 102
3-43 Company C Failure Frequencies 103
3-44 Company D Failure Frequencies 103
3-45 Company E Failure Frequencies 104
3-46 Company F Failure Frequencies 104
3-47 Company G Failure Frequencies 105
3-48 Company H Failure Frequencies 105
3-49 Company K Failure Frequencies 106
4-1 Pumping Well Failure Comprehensive Tree 110
4-2 Pumping Unit Failure Tree 111
4-3 Tubing Failure Tree 112
4-4 Sucker Rod Failure Tree 113
4-5 Downhole Pump Failure Tree 114
4-6 Casing Failure Tree 115
4-7 Wellhead Failure Tree and Notes 116
4-8 Sucker Rod Pumping System Stoppage Tree 118
4-9 Total Failure Frequency (Probability) 121
4-10 Andrews Failure Frequency (Probability) 122
4-11 Denver Failure Frequency (Probability) 123
4-12 Wasson Failure Frequency (Probability) 123
5-1 The Total Failure Frequency Distribution For All Companies 144
5-2 The Pump Failure Frequency Distribution For All Companies 145
5-3 The Rod Failure Frequency Distribution For All Companies 146
5-4 The Tubing Failure Frequency Distribufion For All Companies 147
5-5. Regression Curves of Failure Frequencies 150
XUl
CHAPTER 1
INTRODUCTION
This thesis serves the research project. The Artificial Lift Energy Optimization
Consortium (ALEOC), which is funded by eleven oil companies in the Permian Basin.'*'
Today, as operators continually strive to cut operating costs and extend economic limits
of wells, proper equipment selection and efficient operating practices are becoming more
and more important. The ALEOC was formed to create a central informational database
including operating costs for lift systems, selection guidelines for proper lift methods,
correct lift-equipment sizing and operating procedure utilization for optimizing
production and decreasing lifting costs. The objectives of ALEOC are to share successes
and failures in production operations between consortium members, thereby reducing
present operating costs, increasing lift efficiency, extending lower-rate well producing
life and increasing oil well profitability. ALEOC will provide factual information to
producers that will ensure lower operating costs based on analysis of previous
experiences and implementations of existing technology. An important contribution by
the consortium will be to reduce the number of trials and evaluate new products,
recommended practices and services.
The Permian Basin of West Texas and Southeast comer of New Mexico is one of
the largest mature petroleum production bases in the world'"'' '"*'• ''*'• ' '' ' '. The oil
production is about a quarter of that in the United states. Estimates of petroleum
resources in the Permian Basin suggest that there are about 100 billion barrels of original
oil in place in known fields. The name "Permian Basin" derives from the city and
province of Perm, west of the Ural Mountains in the former Soviet Union. Other places in
the earth where such sedimentary beds occur have likewise received the designation of
Permian, since they were all formed during the same geological age. The producing area
of the Permian Basin is almost square, measuring about 260 miles on each axis (Fig 1-1).
The Texas portion of the Basin extends from Lubbock County and its neighbors on the
Roswell
LUBBOCK
HOCKLEY
Levelland Lubbock
LYNN
BORDEN
HOWARD
GLASSCOCK
KING
Colorado City • NOLAN
MITCHELL -L .
COKE
STERLING ,1
IRION
CROCKETT
San Angelo
TOM GREEN
SCHLEICHER
SUTTON
VAL VERDE EDWARDS
Fig. 1-1 The Permian Basin (From Walter Rundell, Jr., 1982, p.2)
Shallow-water platform reservoirs
Fig. 1-2 Permian Basin Geological Composition
(From West Geological Society, 1996, p.8)
north to Crockett County on the south. The east-west boundaries go from Tom Green to
Culberson County.
The New Mexico section of the Basin consists of Lea County and portions of Eddy,
Chaves, and Roosevelt counties. The Permian Basin is mainly composed of Delaware
,..,pl,.l.,,., , I ,, I I ,. -p.^.^.f^.)M.,-y»,...pi^.|...n-p.,...).-^|-—T^-l-^-.-T^-T-^-'-r^T-'T"'" r"' I ' I ' I " I I T " I • I ' I ' I ' I ' I ' I 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95
Fig. 2-8 Denver Unit Production and EOR History
(From West Texas Geological Society, 1996, p. 205)
14
underlain by an essentially inactive aquifer, solution-gas was the primary producing
mechanism in the early days. Table 2-1 shows a summary of the basic project data.
Although some production occurred from the gas cap, primarily before utilization. Shell's
policy during the water flooding operations was to leave the gas cap unexploited to
conserve reservoir energy and prevent waste by the migration of oil into the gas cap.
When utilization was effected in 1964, the geologic concept of the reservoir was a
simplistic one and was markedly different from the rather complex model that has
evolved today. The original definition of the San Andres reservoir was based on gross
geologic correlations of the reservoir-quality rock and the assumption that this rock
largely was interconnected over the entire extent of the unit. The old geological concept
led to the original peripheral injection design (Fig. 2-10). Wherein existing producers
along the periphery of the unit were converted to injectors during 1964-66. As the
waterflood progressed, it became apparent that the peripheral flood design was not
effective; the water injection wells were located thousands of feet distant from the interior
producers, which have no backup injection.
An in-depth geological interpretation was made using detailed well log and core data
as well as the environmental conditions that controlled original rock deposition. This
investigation was focused on the rock continuity that can be expected between two
adjacent wells. This distance for the Denver Unit was about 1300 ft., i.e., 40-acre well
spacing. The study indicated that the San Andres rock sequences are well-bedded and
that impermeable barriers have relatively wide lateral extent. The permeable layers
showed discontinuities and exhibited the highly varying permeability commonly
associated with carbonates, but no ordered anisotropy was detected. These data
suggested that waterflooding in this carbonate reservoir should be highly efficient at the
proper producer/injector spacing and that, in view of pay discontinuities, unflooded oil
would be left behind in the reservoir at 40-acre well spacing. This type of work ga\ e rise
to the new geological concept of "continuous" and "discontinuous" pay. Continuous pay
Table 2-1 Summary of the Denver Project Data (From W.K. Ghauri, 1980, SPE 8406)
PARAMETERS DESCRIPTION & VALUES
Formation Permian San Andres dolomite Structure Anticline Average depth, ft (m) 5,200 (1585) Gas/oil contact, ft (m) - 1,325 ( - 404) Oil/water contact, f t (m) - 1,400 to - 1,650 ( - 427 to - 503) Average porosity, % 12 Average permeability, md ± 5 Average net oil pay thickness, ' ft <m) 137(41.8) Oil gravity, "API (g/cm^) 33 (0.86) Reservoir temperature, °F("C) 105(40.6) Total acres (m2) in entire reservoir 62,500(253x10® m^) Number of acres (m2) 27,848(113 x 10« m^) Number of productive acres (m^) 25,505 (103 x 10® m^) Date reservoir discovered April 15,1936 Date Texas Railroad Commission approved injection Oct. 14,1964 Date of first injection Nov. 1,1964 Date unitization effective Nov. 1,1964 Primary producing mechanism Solution gas (depletion) Flood pattern Inverted nine-spot and
peripheral Number of wells (at completion of 1978 Infill) 1,217
Producers 860 Injectors 3^3 Plugged and abandoned 14
Original reservoir pressure, psi(MPa) 1,805(12.45) Bubble-point pressure, psi (MPa) 1,805(12.45) Average pressure at start of secondary recovery,
psi (MPa) =fc800/=fc1,100(±5.5/=b7.6) Initial oil formation volume factor 1.312 Solutlon-gas/oil ratio at original pressure,
cu ft/bbi (m3/m3) - • • • 420(76) GOR at start of secondary recovery, cu ft/bbI (m^/m^) 4,060 (731) GOR at current conditions, cuft /bbl(m3/m3) ± 6 0 0 ( ± 1 0 8 ) Oil viscosity at 60*F(15.6*C) and ±1 ,100 psi
(0.76 MPa), c p ( P a s ) 1 . 1 8 ( 1 . 1 8 x 1 0 - 3 ) Original oil in place (Denver Unit Engmeering Committee) , - bbl(m3) S-:I2!'':1S9 S^^^^'^Ss Revised original oil in place,*• bbl (m^) 2.166 x 10^ (0.344 x lO^) ''Tt>H^^^. °'.^'.°''."':*.'°".^.'."!*'^'"'" °* ""''.' 185.643.000 (2.95 x 10®) Cumulative oil production since unitization as of
Sept 1 1978 bbl (m^) 421,748,000(6.7 x 10®) 1977 average dkily oil production rate, B/D(m3/d) . . . 137,200 (21.8x 10^) Cumulative gas production at initiation of unit, . n o ^ . n 9 / i i A^•^n9^
c u f t ( m 3 ) 4 0 Z X 1 U n i . ^ x i u ; Cumulative gas production since unitization to ^«9/^o « ^-•n9x
Seot 1 1 ^ 8 cu ft (m^) 442 x 10" (12.5 x 10") 1977 average dkily gas production rate, cu ft/D (m^/d) 85 x 10® (2.41 x 10®) Cumulative water production at initiation of unit,
bbl (m^) 3,163,000 (OOJ X i u ) ""Teot^V'To^l'b't^'jm^^f'^^ ' ' " ' ^ " . " * " ^ ' ' ° " 241.570,000 (3841 x 103) 1977 average dkily water production rate, B/D(m3/d) 153,000(24.3x103)
' ' " b ' E u m T ^^'^' '"^^''*'' '" ' ° ^^' ' ' ' '' '^^^' 1,382.190.000 (219.75 x 10®) 1977 averagedai iy water injection rate, B/D(m3/d) . . 457 ,300(72 .7x103) Source of iSjection water Ogallala and produced
•Does not include deeper Mg oil pay penetrated in one of the infill proorams; does not include gas-cap pay. ••Includes MQ pay.
16
is that portion of the total net pay that is correlatable or connected between two adjacent
wellbores at the well spacing existing in a particular reservoir. Discontinuous pa\ is the
balance of the net pay not connected between two adjacent wellbores. In such a reservoir,
if one were to drill infill wells at a spacing closer than existed previously, some of the
discontinuous pay would become continuous in the sense that a larger percentage of the
total net pay would be correlatable between closer adjacent wellbores in the waterflood
development pattern. A qualification of pay continuity for the Denver Unit suggested
that if the well spacing were to be reduced from 40 to 20 acres per well, pay continuity
would be enhanced significantly and the reserves would be increased accordingly.
Additionally, in a pattern drive project with impermeable barriers extending over
distances of several well locations, the injected fluids in a permeable pay member will be
contained and will provide the drive within the pay member with a minimum of
crossflow occurring in the reservoir from one pay member to another. The present
subdivisions of the San Andres reservoir in the Denver Unit is shown in Fig. 2-6.
structure continuity, and (4) waterflood induced fractures. While the geological setting
carmot be changed, by converting to the line drive pattern, injecfion can be accomplished
without fracturing. To improve injectivity, WAG cycle lengths have been extended from
every six months to yearly.
2.2.2.4 Denver Unit WAG Development
Although early EOR performance of the Continuous Area was xQvy encouraging, gas
production rates continued to rise steadily. Further, many wells have begun to flow and
severe east/west wells were "'gassing out" and were forced to be shut in. A careful
comparison of the performance of the Denver Unit Continuous and WACO, Areas with
other Wasson Area CO2 flood demonstrated the advantages of both Continuous and
WAG injection. Numerical models were refined based on actual observed CO2 flood
performance in each area of the Denver Unit, then the models were used to investigate
various flood options. Sfimulation studies suggest that the Denver Unit WAG (DUWAG)
injection process, in which four to six years of continuous CO, injection is followed by
1:1 WAG, has advantages over both continuous CO2 and conventional WAG processes.
The DUWAG process combines the early EOR response of continuous injecfion and the
higher ultimate recovery of WAG injection. The WAG portion of the process provides
38
Q
CQ
UJ
OIL
0 j i i i n ! i i i i i | i ! i i M m M | M i i i i i m n i m i i i r m | t T r i i i i i i i H T T T r i m M H i M i i i M i i i 1983 1984 1985 1986 1987 1988 1989
Fig. 2-18 Denver Unit WACO2 Area Oil Producfion History
(From C.S. Tanner et al., 1992, SPE 24156)
6 4
• A A
6 5
A 7 4
A
A
A
A
8 4
A A A 75
A A
A A
A
A A •
66
76
A
A * I. LEGEND
• PRODUCERS
m SHUT-IN WELL
A NtWLY CONVERTCO WACOa INJECTORS
J ^ ORKMNAL »-«M3T WAOOa INJECTOfW
A A A
9 * • • * 8 5 86
Fig. 2-19 Denver Unit WACO2 Area Project Patterns
(From C.S. Tanner et al., 1992, SPE 24156)
39
improvement to areal sweep efficiency and the prolonged economic life of the east/west
and infill wells, which would have ''gassed ouf' under continuous flooding. Further
stimulafions predict that a large slug size (60% HCPV) could result in additional EOR
recovery, using existing wells and facilities, without increasing the peak gas production
rates. To test the DUWAG process in the field, four patterns in the heart of the
Continuous Area were converted to this process. These patterns were characterized by
high CO2 injecfivity and high CO2 producing rates, and included several flowing wells.
During this test, water injection rates were successfully attained at pressures below
fracture pressure. Despite the lower injectivity of water, the water injection volumes
were achievable because of the large CO2 slug already in place. On the production side,
within a month of initiating WAG injection in these patterns, CO2 production rates began
to drop, while oil and water production rates remained constant. Implementation of the
Denver Unit WAG process has not only reduced anticipated peak gas rates, but has also
allowed accelerated expansion of the CO2 flood to the Final Injection Area (FIA) by
freeing up CO2 from the IIA. This more rapid expansion provides increased oil
production as these patterns respond to COj.
2.2.2.5 Recent CO2 Flood Performance
The two major components of the DUWAG project were (1) the conversion of the
Continuous Area to this injection process, and (2) the accelerated expansion of the CO2
flood to the FIA. Field installafion of the project began in late 1989.
2.2.2.5.1 Continuous Area. As of October, 1991, 56 patterns (of 94 patterns) in the
Confinuous Area have been switched to WAG injection. Since mid-1991 the DUCRP
has been operafing at maximum capacity. Therefore, as producing gas rates continue to
rise, some Confinuous Area wells have been shut-in pending completion of the plant
expansion in early 1992. Because the predicfion of the follow-up water injectivity is very
important to the success of the project being able to accurately match and predict fluid
injecfivities is of vital importance. Field evidence from the Denver Unit suggests a water
40
injecfivity reducfion of approximately 30% following the CO2 injecfion cycle. Over the
period of the water injection cycle, the trapped gas was slowly dissolved, resulting in
increased injectivity during the water portion of the WAG cycle.
2.2.2.5.2 WACO, Area. Due to the more encouraging response observed in the
Confinuous Area, a slug of confinuous CO2 was injected into the WACO2 Area. This
work began in mid-1990, and production response has been encouraging. Fig 2-20 and
Fig. 2-21 show the recent injection status and the recent oil production response for the
WACO2 Area. After the continuous CO2 injection was initiated, oil response began to
increase dramatically.
nOBERTB UNIT (TEXACO)
INJECTION STATUS PATTERNS ON INITIAL C02 INJECTION CYCLE
H PATTERNS ON WATER CYCLE OF DUWAO
I.': I PATTERNS ON WATER INJECTION
Fig. 2-20 Recent Injecfion Status (From C.S. Tanner et al, 1992, SPE 24156)
2.2.2.5.3 Final Injection Area. Expansion of the CO2 flood to the FIA has progressed
rapidly. Since the DUWAG project was approved in late 1989, 92 new FIA patterns have
begun CO2 injecfion. By the end of 1991, patterns including 91% of the Denver Unit oil
column OOIP were under CO2 injection. The only patterns yet to begin COj injecfion are
41
Q Q. O CD
YEAR
Fig. 2-21 Recent Oil Producfion Response for the WACO2 Area.
(From C.S. Tanner et al., 1992, SPE 24156)
a few patterns in the center of the unit (due to special considerations in equipping CO2
injection wells within city limit), and patterns associated with leaseline areas, which are
planned to be developed with offset operators. Early indication of EOR production
response have been encouraging in the FIA. Several of the more mature FIA CO2
injection patterns have been switched to DUWAG injection in an effort to reduce gas
production rates.
2.3 Denver Unit Sucker Rod Pumping Failures
Denver Unit sucker rod pumping wells are the biggest group among those in Wasson
field and in Shell producfion units. Active pumping well numbers and failures of pump,
rod and tubing in years of 1992 through 1996 are listed in Table 2-2. To make the failure
data more reasonable to compare, failure frequencies were calculated, which are listed in
Table 2-3. Fig2-22 is the failure frequency graph which looks more straightforward. From
Fig. 2-22, it can be seen that the failure frequencies decrease year by year. This may be
the result of (1) better and better operations in the field, (2) better and better facilities and
equipment, (3) better working condifions of pump, rod and tubing due to better flow
42
Table 2-2 Denver Unit Sucker Rod Pumping Failures
Years
1992 1993 1994 1995 1996
Active Well Numbers
539 544 554 590 591
Pump Failures
349 207 162 191 134
Rod Failures
176 108 84 145 127
Tubing Failures
137 90 70 68 66
Total Failures
758 442 366 439 350
Table 2-3 Denver Unit Sucker Rod Pumping Failure Frequency
O 0.700 z UJ => 0.600 o UJ OC 0.500 u. UJ a: 0.400 < 0.300 u.
0.200
0.100
0.000
1990 1991 1992 1993
YEAR
1994 1995 1996
Fig. 3-10 Midland Pump Failure Frequencies
85
0.000
A(71A')
B(186A')
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-11 Midland Rod Failure Frequencies
86
0.600
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-12 Midland Tubing Failure Frequencies
87
>-o z UJ
1.800
1.600
1.400
1.200
2 1.000 OC
UJ 0.800 oc
d 0.600 < u.
0.400
0.200
0.000
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-13 New Mexico Total Failure Frequencies
0.800
0.700
> 0.600 z UJ D 0.500 a UJ pC 0.400 u. UJ
£ 0.300
< 0.200
0.100
0.000
-•-A(108A')
-•-C(131A')
-><- D(245/Y)
1990 1991 1992 1993
YEAR
1994 1995 1996
Fig. 3-14 New Mexico Pump Failure Frequencies
88
>-
o z UJ 3 a UJ oc II UJ
oc J < u.
0.800
0.700
0.600
0.500
0.400
0.300
0.200
•A(108A')
•C(131/Y)
•D(245A')
0.100
0.000
1990 1991 1992 1993 1994 1995 1996
YEAR
Fig. 3-15 New Mexico Rod Failure Frequencies
0.300
0.250
0.050
•A(108/Y)
•C(131A')
D(245/Y)
0.000 1990 1991 1992 1993 1994 1995 1996
YEAR
Fig. 3-16 New Mexico Tubing Failure Frequencies
89
1.6
1.4
> 1.2 O
UJ 1 a UJ cc 0.8 u. UJ oc 0.6
0.4
0.2
0
>-o z UJ Z)
o UJ oc u. UJ oc
0.7
0.6
0.5
0.4
0.3
< 0.2
0.1
B(63A')
CCHOA')
D(546A')
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-17 Denver Total Failure Frequencies
B(63/Y)
C{^40rY)
D(546A^)
1990 1991 1992 1993 1994 1995 1996
YEAR
Fig. 3-18 Denver Pump Failure Frequencies
90
> o z UJ
D o UJ OC u. UJ
oc < u.
0.5
0.45
0.4
0.35
0.3
0.25
0.2
0.15
0.1
0.05
0
• • - B(63A')
-m- C(140/Y)
-X-D(546A')
1990 1991 1992 1993 1994 1995 YEAR
Fig. 3-19 Denver Rod Failure Frequencies
1996
>-o z UJ
0.3
0.25
0.2
O UJ OC 0.15 u. UJ
oc d 0.1
0.05 B(63A')
C(140/Y)
D(546A')
0
1990 1991 1992 1993 1994 1995 YEAR
Fig. 3-20 Denver Tubing Failure Frequencies
1996
91
>-o z UJ
0.9
0.8
0.7
0.6
2 05 OC
m 0.4 OC
3 0.3
0.2
0.1
0
B(175A')
C(409/Y)
D(355A')
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-21 Levelland Total Failure Frequencies
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-22 Levelland Pump Failure Frequencies
92
o z UJ
0.4
0.35
0.3
0.25 O UJ OC 0.2 u. UJ
§ 0.15
0.1
0.05
0
1990 1991 1992 1993
YEAR
1994
B(175A')
C(409A')
D(355A')
1995 1996
Fig. 3-23 Levelland Rod Failure Frequencies
0.2
0.18
0.16
O 0.14 z UJ 3 0.12
a UJ OC 0.1 u. UJ
oc 0.08
< 0.06
0.04
0.02
J_ B(175A')
C(409A')
D(355A')
0 1990 1991 1992 1993 1994 1995 1996
YEAR
Fig. 3-24 Levelland Tubing Failure Frequencies
93
>-o z UJ D o UJ OL u. UJ
A(326A')
B(170A')
C(121/Y)
D(516/Y)
0.600
0.400
0.200
0.000
1990 1991 1992 1993 1994 1995 1996
YEAR
Fig. 3-25 Wasson Total Failure Frequencies
0.600 A(326A')
B(170A')
C(121A')
0(516 1 )
0.000
1990 1991 1992 1993 1994 1995 1996
YEAR
Fig. 3-26 Wasson Pump Failure Frequencies
94
0.500
0.450
0.400
O 0.350 f i
UJ •D 0.300 o UJ
Q: 0.250 UJ
^ 0.200
< 0.150
0.100 0.050
0.000
•A(326A')
•B(170A')
•C(121A')
•D(516/Y)
1990 1991 1992 1993 1994 1995
YEAR
Fig. 3-27 Wasson Rod Failure Frequencies
1996
0.250
0.200
>-o z UJ
3 0.150
a UJ oc u. UJ
oc 0.100 < u.
0.050
0.000
•A(326A')
•B(170A')
•C(121A')
•D(516/Y)
1990 1991 1992 1993 1994 1995 1996
YEAR
Fig. 3-28 Wasson Tubing Failure Frequencies
95
2.5
> • o z UJ
a UJ oc u. UJ
oc
1.5
0.5
0
•B(116A')
D(139/Y)
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-29 Monahans Total Failure Frequencies
> • o z UJ 3
o UJ OC u. UJ oc
0.7
0.6
0.5
0.4
0 3
< 0.2
0.1
B(116A')
DCISgA')
0
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-30 Monahans Pump Failure Frequencies
96
B(116A')
D(139/Y)
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-31 Monahans Rod Failure Frequencies
0.3
0.25 > •
o m 0.2
a UJ oc 0.15 u. UJ
oc 3 0.1
0.05
B(116A')
D(139A') —X
1990 1991 1992 1993 1994 1995 1996
YEAR
Fig. 3-32 Monahans Tubing Failure Frequencies
97
>
o z UJ D
o UJ OC u. UJ oc 3 _J <
1.4
1.2
1
OR
0.6
0.4
0.2
0
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-33 MSAU-ANDREWS Total Failure Frequencies
>-o z UJ
0.6
0.5
0.4
-•-B(521A') { |-»-C(47/Y)
a UJ
P 0.3 UJ
oc 0.2
0.1
0 1992 1993 1994 1995 1996
YEAR 1990 1991
Fig. 3-34 MSAU-ANDREWS Pump Failure Frequencies
98
>-o z UJ
0.45
0.4
0.35
0.3
2 025 OC
H] 0.2 OC
3 0.15 < u.
0.1
0.05
0
B(521A')
C(47/Y)
1990 1991 1992 1993 1994 1995 1996
YEAR
Fig. 3-35 MSAU-ANDREWS Rod Failure Frequencies
>-o z UJ
o UJ oc u. UJ
oc < u.
0.25
0.2
0.15
0.1
0.05
0 1993 1994 1995 1996
YEAR 1990 1991 1992
Fig. 3-36 MSAU-ANDREWS Tubing Failure Frequencies
99
1990 1991 1992 1993 1994 1995 YEAR
Fig. 3-37 Sundown Total Failure Frequencies
1996
>-o z UJ D
a UJ oc u. UJ
oc < u.
1990 1991 1992 1993 1994 1995 YEAR
Fig. 3-38 Sundown Pump Failure Frequencies
1996
100
> •
o z UJ D o UJ OC u. UJ oc -J < u.
0.45
0.4
0.35
0.3
0.25
0.2
0.15
0.1
0.05
0
1990 1991 1992 1993 YEAR
1994
E(251A')
F(64A')
1995 1996
Fig. 3-39 Sundown Rod Failure Frequencies
0.25
o z UJ D
o UJ OC
S 0.1
0.15
0.05
E(251A')
e - F(64A')
0
1990 1991 1992 1993 1994 1995 1996
YEAR
Fig. 3-40 Sundown Tubing Failure Frequencies
101
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-41 Company A Failure Frequencies
>-o I I I
FRE
QU
UJ OC
—I
FA
I
0.600
0.500
0.400
0.300
0.200
0.100
0.000
1990 1991 1992 1993 1994 1995 1996
YEAR
Fig. 3-42 Company B Failure Frequencies
102
0.7
0.6
>; 0.5
z UJ
a 0.4 UJ OC
g 0.3
1 0.2
0.1
0
1990 1991 1992 1993 1994 1995 1996
YEAR
Fig. 3-43 Company C Failure Frequencies
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-44 Company D Failure Frequencies
103
>-o z UJ Z) a UJ oc u. UJ oc
1990 1991 1992 1993 YEAR
1994 1995 1996
Fig. 3-45 Company E Failure Frequencies
>-o
0.8
0.7
0.6
^ 0.5
a UJ oc 0.4 U-UJ
§ 0.3
0.2
0.1
PUMP
ROD
TUBING
TOTAL
1992 1993 1994 1995 YEAR
1990 1991
Fig. 3-46 Company F Failure Frequencies
1996
104
>-
o z UJ D
o UJ OC u. UJ oc D -1 < u.
0.9
0.8
0.7
0.6
0.5
0,4
0 3
0.2
0.1
PUMP ROD
TUBING TOTAL
1990 1991 1992 1993 YEAR
1994 1995 1996
Fig. 3-47 Company G Failure Frequencies
>-o z UJ D O UJ oc u. UJ oc D
0.5
0.45
0.4
0.35
0.3
0.25
0.2
0.15
0.1
0.05
0
PUMP ROD
TUBING TOTAL
1993 YEAR
1994 1995 1990 1991 1992
Fig. 3-48 Company H Failure Frequencies
1996
105
1990 1991 1992 1993 1994 1995 1996 YEAR
Fig. 3-49 Company K Failure Frequencies
3.4 Some Observations of the Tables and Graphs
From the above tables and graphs, it can be observed that (1) different companies
have very different operation management and data organizing modes, some are more
efficient and easier to access their useful data; (2) different companies have very different
failure frequencies which to some extent are the criteria to judge their field operation
efficiency, facility manipulation, underground working conditions of the sucker rod
pumping equipment and so forth; (3) there is a trend of failure frequency decrease among
the participated companies with few exceptions, (4) generally speaking pump failure
frequency is the largest compared with those of sucker rod and tubing for all the sucker
rod pumping wells, (5) to attain a better picture of the Permian Basin sucker rod pumping
failures, further endeavor may be exerted on the statistical analysis of the provided data.
106
3.5 Summary
From the tables and graphs in this chapter, the following observations have been made.
• To obtain the required data some of the provided Access files have to be converted
and sorted to Excel files;
• With the reorganized Excel files, active well numbers and classified failures may be
counted;
• To compare the failures of the sucker rod pumping system, failure frequency should
be introduced. Failure frequency is calculated by failure numbers and active well
numbers;
• To be more straightforward, the failure frequency tables have been plotted to
graphs;
• From the generated tables and graphs, some phenomena have been observed.
107
CHAPTER 4
APPLICATION OF FAULT TREE ANALYSIS
TO SUCKER ROD PUMPING SYSTEM
4.1 Introduction
Fault Tree Analysis (FTA) was first developed in 1961-62 by H. A. Watson of Bell
Telephone Laboratories under an Air Force study contract for the Minuteman Launch
Control System. "* ' ' ^ Since then it has been widely used to improve the safety of various
systems in military, aerospace, mining and nuclear industries. It has been often used as a
failure analysis tool by reliability experts. Sucker rod pumping is the most widely used
form of artificial lift in the world. Failures of the sucker rod system have caused millions
of dollars' loss in the world. The Permian Basin is one of the largest oil production bases.
It would be most beneficial to guarantee the normal operation of sucker-rod systems in
this area. Oil companies are now seeking measures to reduce the failures of the sucker rod
pumping system. There are many methods utilized in the fault diagnosis of the sucker rod
pumping system, but most of them are valid only in some cases. The use of FTA to
analyze failures of the sucker rod system will result in better decision making. This
research program is supported by more than eleven oil companies in the Permian Basin.
When this project is accomplished, it is expected to find out the main failure causes for
different companies and for different production units, and to make the sucker rod
pumping systems much more efficient and effective.
4.2 Definition of Failures
The failures of sucker rod pumping wells are undesired events. Such events usually
arise in the sucker rod pumping systems that have a history of recurring faults. Past
failure records have indicated that the systems and events qualify for FTA.
In defining an undesired event, first determine all the undesired events in an operating
system. In a sucker rod pumping system, the stoppage of operafion may be caused by (1)
equipment failure or failures, and (2) failure or failures of the well itself Equipment
108
failure(s) may be caused by the pumping unit, the sucker rod string, and the downhole
pump. Well failure(s) may cause equipment failure(s), that is, well failure(s) may be
incorporated in the equipment failure(s) or malfunction(s). Detailed failures of the system
will be presented on Fig. 4-1 through Fig. 4-7.
4.3 Understanding the System
After defining an undesired event, the next task is to gain an understanding of the
system selected for FTA. The important part of this step is gaining knowledge of system
operations and interactions. All available information about the system and its
environment should be studied. The information should include system drawings,
layouts, schematics, specifications, pictures, diagrams, operating manuals, and
information gained from experienced people. Any data of the system can be useful.
For the sucker rod pumping system, operation can be guaranteed by electricity,
linking and control components and fluid flow in reservoir and in vertical and horizontal
pipes. Any factor causing trouble with them may result in failure of the whole system.
4.4 Construction ofthe Fault Tree
Fault tree construction is a logic process that produces a diagram displaying all
possible causes ofthe undesired event. The process starts with the undesired event, here
the pumping well failure, at the top ofthe tree. Reasoning backward from the top event,
the events (primary events, here equipment failures and well failures) that could directly
cause the top undesired event are shown immediately below. They are input events to the
top event. Logic gates indicate the relationships between these primary causes in
producing the undesired events.
Each primary event is an output event, and each is analyzed to determine its causes.
The logic process continues for each event identified and ends with independent or
undeveloped events. Throughout the process, logic gates show how input events interact
to produce each output event. The fault tree for a sucker rod pumping system is as shown
on Fig. 4-1 through Fig. 4-7.
109
4.5 Evaluation of the Fault Tree
After constructing the fault tree, the next step is to evaluate the tree. In the evaluation,
determine the circumstances under which each ofthe bottom events could occur. In
making this determination, the relative likelihood or probability of occurrence of these
independent or undeveloped events is also assessed. Probabilities result from test results,
experience, published data, accident and incident records, or engineering judgment. The
likelihood ofthe output events immediately above the bottom events is then determined
from the probabilities. The evaluation process continues up the tree until determining the
likelihood for the undesired event shown at the top.
Mathematical techniques for combining and simplifying the fault tree probabilities
may be used to perform a quantitative evaluation. There are many factors to determine:
the overall likelihood ofthe undesired event, the combination of events most likely
leading to the undesired event, the events that contribute the most to this combination,
and the most likely event sequences or paths to the top ofthe tree.
pumping unit failure
tubing failure
JL equipment failure
OR
sucker-rod string failure
pumping well failure
OR
downhole pump failure
well failure
OR
± casing failure
well head failure
Fig. 4-1 Pumping Well Failure Comprehensive Tree
110
pumping unit failure
OR
counterbalance part failure
motor does not work
power transmission part failure
movement conversion part failure
bearing failure
OR
Fig. 4-2 Pumping Unit Failure Tree
111
tubing failure
OR
tubing body failure
tubing connection failure
OR OR
thread damage
OR
Fig. 4-3 Tubing Failure Tree
112
sucker-rod failure
OR
polished rod
failure sucker-rod
string failure
OR OR
body failure
connection failure
pin failure
OR
thread failure
thread failure
Fig. 4-4 Sucker Rod Failure Tree
113
downhole pump failure
OR
pump malfunction
pump parts failure
OR OR
gas interference
Incomplete tillage
JL plunger or travelling valve leak
standing valve leak
barrel failure
plunger failure
travelling valve failure
standing valve failure
Fig. 4-5 Downhole Pump Failure Tree
114
casing failure
OR
casing thread failure casing body failure
OR OR
casing collapse
/ formation \ I creep J
Fig. 4-6 Casing Failure Tree
115
output event
undeveloped event (not necessary or lack of information to develop further)
independent event
OR OR gate, representing a situation In which any of the events shown below the gate (input events) will lead to the event shown above the gate (output event) The output event will occur if and only If one or any combination of the input events exist.
AND AND gate, representing a condition in which all the events shown below the gate (Input events) must be present for the event above the gate (output event) to occur The output event will occur only if all of the Input events exist simultaneously.
Fig. 4-7 Wellhead Failure Tree and Notes
116
Failure probability at any level, P. can be calculated using the following equations: n n
P = Z P. = Z 1 - R, (t) for OR gates fault trees i=l 1=1
n n
P = n Pi = n 1 - Ri (t) for AND gates fault trees i=l
R,( t ) -e -i=l
->Mt
where, P,—-the probability of failure ofthe i" component on the next lower le\el;
2. Walter Rundell, Jr., Oil in West Texas and New Mexico, Texas A&M Universit\' Press, College Station, 1982, p.2.
3. West Texas Geological Society, Permian Basin Oil and Gas Fields, Fall Symposium, Publication No. 96-101, Oct. 31- Nov. I, 1996, p.8.
4. West Texas Geological Society. Inc., Synergy Equals Energy—Teams. Tools, and Techniques, Publication No. 94-94, Oct. 31-Nov. 1, 1994, p. 102.
5. National Petroleum Bibliography, Petroleum Exploration & Development Map— Permian Basin, 1963.
6. M. H. Holtz et al.. Geological and Engineering Assessment of Remaining Oil in a Mature Carbonate Reservoir: An Example From the Permian Basin, West Texas. (SPE 27687)
7. W. K. Ghauri, Production Technology Experience in a Large Carbonate Waterflood, Denver Unit, Wasson San Andres Field. (SPE 8406)
8. C. S. Tanner et al.. Production Performance ofthe Wasson Denver COj Flood. (SPE/DOE 24156)
9. West Texas Geological Society, Oil & Gas Fields In West Texas, Volume VII. 1996, pp.128, 198-206.
10. C. E. Foxet et al.. The Denver Unit CO2 Flood Transforms Former Waterflood Injectors into Oil Producers. (SPE 27674)
11. E.A. Fleming et al., Overview of Producfion Engineering Aspects of Operating the Denver Unit C02 Flood. (SPE/DOE 24157)
12. G.F. Lu et al.. Geological Distribution and Forecast Models of Infill Drilling Oil Recovery for Permian Basin Carbonate Reservoirs. (SPE 26503)
13. U.S. Department of Labor, Mine Safety and Health Administrafion. and Nafional Mine Health and Safety Academy. Fault Tree Analysis, revised 1991, Washington, DC.
14. Alan H. Woodyard, Risk Analysis of Well Complefion Systems, SPE 9414, April, 1982.
15. Robert M. Bethea et al., Statisfical Methods for Engineers and Scienfists, Marcel Dekker, Inc., New York, 1985.
155
16. A. Hald, Stafistical Theory with Engineering Applications, John Wile\ & Sons, Inc., New York, 1952.
17. Stuart L. Meyer, Data Analysis for Scientists and Engineers, John \\^ile\ & Sons, Inc., New York, 1975.
18. Databases from 11 Oil Companies.
156
PERMISSION TO COPY
In presenting this thesis in partial fulfillment of the requirements for a
master's degree at Texas Tech University or Texas Tech University Health Sciences
Center, I agree that the Library and my major department shall make it freely
available for research purposes. Permission to copy this thesis for scholarly
purposes may be granted by the Director of the Library or my major professor.
It is understood that any copying or publication of this thesis for financial gain
shall not be allowed without my further written permission and that any user