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EXECUTIVE REPORT ON A NEW VERTICAL EXPLORATION WELL
PROPOSED FOR DRILLING IN A NEWLY LICENSED GORDON-X
FIELD
A COURSE-WORK/PROJECT
ON
“DRILLING OPTIMIZATION PET 606”
BY
OSSAI GODWIN OYINDOBRA PATRICK [MAT NO: 20134873398]
[CLASS OF 2013/2014]
FULL-TIME POST GRADUATE STUDIES [MEng]
SUBMITTED TO
DR. OHIA
THE DEPARTMENT OF PETROLEUM ENGINEERING
FEDERAL UNIVERSITY OF TECHNOLOGY, OWERRI
F.U.T.O
AUGUST, 2015
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TABLE OF CONTENTSection 1.0
Introduction
Section 1.1
Report Overview
Section 1.2
Objective of planning the well
Section 1.3
Safety of personnel and the proposed well
Section 1.4
Minimum Cost
Section 1.5
Usable Holes
Section 1.6
Well-Type Classifications
Section 1.7
Formation Pressure
Section 1.8
Planning Cost
Section 2.0
Literature Review
Section 2.1
Offset-well Selection
Section 2.2
Data Sources
TABLE OF CONTENT3
Section 3.0
Main Report Analysis
Section 3.1
Importance of pore and fracture pressures when planning a well
Section 3.2
Determination of pore pressures
Section 3.3
Typical mud system and its relevant components/functions
Section 3.4
Determination of mud pit capacity
Section 3.5
Gas ingress while drilling and steps to be taken to regain control of the well
Section 3.6
Functions of the units that comprise a typical BOP
Section 3.7
Down hole equipment design for the well
LIST OF FIGURESFig 1.0
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Flow chart/path for well planning
Fig 2.0
Well cost can be reduced dramatically if proper planning is implemented
Fig 3.0
Cos per foot for the bit run
Fig 4.0
Depth vs. days plot developed from a mud record
Fig 5.0
A typical scout ticket
Fig 6.0
A typical section of a mud log
Fig 7.0
Layout of a typical drilling mud system
Fig 8.0
Open hole design schematics applied for the well
Fig 9.0
The exploratory well design schematics based on given data
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LIST OF TABLESTable 1.0
Characteristics of various well types
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Table 2.0
A typical average trip times
Table 3.0
API Drill Pipe Grade US customary unit
Table 4.0
API Drill Pipe Grade SI unit
Nomenclature:CB = bit cost, U.S. dollars
CR = rig cost, U.S. dollars
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d = diameter, in.
dDS = drillstring diameter, in.
dH = hole diameter, in.
D = deepest interval, ft
Di = depth of interest, ft
Dn = deepest normal zone, ft
pform = formation pressure, lbm/gal
ph = hydrostatic pressure, psi
Qm = mud-flow rate, gal/min
Qp = pump output, bbl/min
TR = rotating time, hours
TT = trip time, hours
v = annular velocity, ft/min
V = annular volume, bbl/1,000 ft
Vα = annular velocity, ft/min
Y = footage per bit run, ft
ρ = mud weight, lbm/gal
ρekick = equivalent mud weight at the depth of interest, lbm/gal
ρo = original mud weight, lbm/gal
Δp = differential pressure, psi
Δρtrip = trip margin, lbm/gal
Δρkick = incremental kick mud weight increase, lbm/gal
Nomenclature:BHA = Bottom Hole Assembly
TVD = True Vertical Depth (m)
MD = Measured Depth (m)
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ECD = Equivalent Circulating Density (kg/m³)
min = minimum
max = maximum
LWD = Logging While Drilling
MWD = Measured While Drilling
MW = Mud Weight or Mud density (kg/m³)
ROP = Rate of Penetration (m/hr)
TD = Total Depth (m)
TVD = Total Vertical Depth (m)
WOB = Weight on bit (daN)
RPM = Revolution per minute
Pf = Formation Pressure (kPa)
Pff = Fracture Pressure (kPa)
v = Poison ratio
ρ = Drilling fluid density (kg/m³)
ρe = Equivalent Mud Density (kg/m³)
C = Constant
σo = Overburden pressure (kPa)
σ’ = Effective stress (kPa)
D&A = Drilled and abandoned
σ’a = Effective horizontal stress (kPa)
Nomenclature:σ’o = Effective overburden stress (kPa)
Vp = Compressional velocity (m/s)
Vs = Shear Velocity (m/s)
Yp = Joint yield strength (kgf)
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σy = Yield stress (kgf)
RFT = Repeat formation test
MDT = Modular dynamic test
σ = Total stress (kPa)
Section 1.0: INTRODUCTIONIn order for us to successfully and safely drill a new vertical exploration well as proposed in the newly licensed Gordon-X field, it is expedient that we also have good background knowledge of planning and designing the well.
Section 1.1: Report Overview
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What is well planning? Well planning is perhaps the most demanding aspect of drilling engineering. It requires the integration of engineering principles, corporate or personal philosophies, and experience factors. Although well planning methods and practices may vary within the drilling industry, the end result should be a safely drilled, minimum-cost hole that satisfies the reservoir engineer’s requirements for oil and gas production.
The skilled well planners normally have three common traits. They are experienced drilling personnel who understand how all aspects of the drilling operation must be integrated smoothly. They utilize available engineering tools, such as computers and third-party recommendations, to guide the development of the well plan. And they usually have an investigative characteristic that drives them to research and review every aspect of the plan in an effort to isolate and remove potential problem areas.
Overview of the Planning Process:
Well planning is an orderly process. It requires that some aspects of the plan be developed before designing other items. For example, the mud density plan must be developed before the casing program because mud weights have an impact on pipe requirements.
Fig 1.0 below give a flow-chart illustration on planning the well:
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Fig 1: Flow chart/path for well planning.
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Bit programming will be done at any time in the plan after the historical data have been analyzed. The bit program is usually based on drilling parameters from offset wells. However, bit selection can be affected by the mud plan (i.e., the performance of polycrystalline-diamond (PCD) bits in oil muds). Casing-drift-diameter requirements may control bit sizing.
Casing and tubing will be considered as an integral design. This fact is particularly valid for production casing. A design criterion for tubing is the drift diameter of the production casing, whereas the packer-to-tubing forces created by the tubing’s tendencies for movement can adversely affect the production casing. Unfortunately, these calculations are complex and often neglected. The completion plan must be visualized reasonably early in the process. Its primary effect is on the size of casing and tubing to be used if oversized tubing or packers are required. In addition, the plan can require the use of high-strength tubing or unusually long seal assemblies in certain situations.
Section 1.2: Objective of planning the well
The objective of planning the proposed new vertical exploration well in the newly licensed Gordon-X field is to formulate from many variables a program for drilling a well that has the following characteristics: safe, minimum cost, and usable. Unfortunately, it is not always possible to accomplish these objectives on each well because of constraints based on geology, drilling equipment, temperature, casing limitations, hole sizing, or budget. But our aim/objective and end result should be a safely drilled, minimum-cost hole that satisfies the reservoir engineer and Gordon Petroleum Corporation’s requirements for oil and gas production.
Section 1.3: Safety of Personnel and the proposed well
Safety should be the highest priority in planning this proposed vertical exploratory well in Gordon-X field. Personnel considerations must be placed above all other aspects of the plan. In some cases, the plan must be altered during the course of drilling the well when unforeseen drilling problems endanger the crew. Failure to
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stress crew safety has resulted in loss of life and burned or permanently crippled individuals.
The second priority involves the safety of the proposed vertical exploratory well. The well plan must be designed to minimize the risk of blowouts and other factors that could create problems. This design requirement must be adhered to rigorously in all aspects of the plan. It is important for Gordon Petroleum Corporation’s management to understand that safety of personnel is topmost priority and must not be compromised at any stage of planning or drilling the vertical exploratory well in the newly licensed Gordon-X field. Example 1.0 below, illustrates a case in which this safety considerations was neglected in the earliest phase of well planning, which is data collection (the importance of safety in well planning, design and drilling cannot be more over-emphasized).
Example 1.0: A turnkey drilling contractor began drilling a 9,000-ft well in September 1979. The well was in a high-activity area where 52 wells had been drilled previously in a township (approximately 36 sq. miles). The contractor was reputable and had a successful history.
The drilling superintendent called a bit company and obtained records on two wells in the section where the prospect well was to be drilled. Although the records were approximately 15 years old, it appeared that the formation pressures would be normal to a depth of 9,800 ft. Because the prospect well was to be drilled to 9,000 ft, pressure problems were not anticipated. The contractor elected to set 10¾-in. casing to 1,800 ft and use a 9.5-lbm/gal mud to 9,000 ft in a 9⅞-in. hole. At that point, responsibility would be turned over to the oil company.
Drilling was uneventful until a depth of 8,750 ft was reached. At that point, a severe kick was taken. An underground blowout occurred that soon erupted into a surface blowout. The rig was destroyed and natural resources were lost until the well was killed three weeks later.
A study was conducted that yielded the following results:
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All wells in the area appeared to be normal pressured until 9,800 ft. However, 4 of the 52 wells in the specific township and range had blown out in the past five years. It appeared that the blowouts came from the same zone as the well in question. A total of 16 of the remaining 48 wells had taken kicks or severe gas cutting from the same zone. All problems appeared to occur after a 1973 blowout taken from a 12,200-ft abnormal-pressure zone.
Conclusion:
The drilling contractor did not research the surrounding wells thoroughly in an effort to detect problems that could endanger his well or crews. The final settlement by the insurance company was more than U.S. $16 million. The incident probably would not have occurred if the contractor had spent U.S. $800 to $1,000 to obtain proper drilling data.
Section 1.4: Minimum Cost
A valid objective of planning the vertical exploratory well proposed in the newly licensed Gordon-X field is to minimize the cost of the well without jeopardizing the safety aspects. In most cases, costs can be reduced to a certain level as additional effort is given to the planning (see Fig. 2.0 illustrated below). It is not noble to build "steel monuments" in the name of safety if the additional expense is not required. On the other hand, funds should be spent as necessary to develop a safe system.
Fig 2: Well costs can be reduced dramatically if proper well planning is implemented.
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Section 1.5: Usable Holes
Drilling a hole to the target depth is unsatisfactory if the final well configuration is not usable. In this case, the term "usable" implies the following:
The hole diameter is sufficiently large so an adequate completion can be made.
The hole or producing formation is not irreparably damaged.
This requirement of the well planning process can be difficult to achieve in abnormal-pressure, deep zones that can cause hole-geometry or mud problems.
Section 1.6: Well-Type Classification
The drilling engineer is required to plan a variety of well types, including: wildcats, exploratory holes, step-outs, in-fills, and re-entries. Generally, wildcats require more planning than the other types. Infill wells and re-entries require minimum planning in most cases.
Wildcats are drilled where little or no known geological information is available. The site may have been selected because of wells drilled some distance from the proposed location but on a terrain that appeared similar to the proposed site. The term "wildcatter" was originated to describe the bold frontiersman willing to gamble on a hunch. Rank wildcats are seldom drilled in today’s industry. Well costs are so high that gambling on well site selection is not done in most cases. In addition, numerous drilling prospects with reasonable productive potential are available from several sources. However, the romantic legend of the wildcatter will probably never die. Characteristics of various well types are shown in Table 1.0 below:
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Table 1.0: Characteristics of various well types
Section 1.7: Formation Pressure
The formation or pore pressure encountered by the well significantly affects the well plan. The pressures may be normal, abnormal (high), or subnormal (low). Normal-pressure wells generally do not create planning problems. The mud weights are in the range of 8.5 to 9.5 lbm. /gal. Kicks and blowout-prevention problems should be minimized but not eliminated altogether. Casing requirements can be stringent even in normal-pressure wells deeper than 20,000 ft because of tension/collapse design constraints.
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Subnormal-pressure wells may require setting additional casing strings to cover weak or low-pressure zones. The lower-than-normal pressures may result from geological or tectonic factors or from pressure depletion in producing intervals. The design considerations can be demanding if other sections of the well are abnormal pressured.
Abnormal pressures affect the well plan in many areas, including: casing and tubing design, mud-weight and type-selection, casing-setting-depth selection, and cement planning. In addition, the following problems must be considered as a result of high formation pressures: kicks and blowouts, differential-pressure pipe sticking, lost circulation resulting from high mud weights, and heaving shale. Well costs increase significantly with geo-pressures.
Because of the difficulties associated with well planning for high-pressure exploratory wells, many design criteria, publications, and studies have been devoted to this area. The amount of effort expended is justified. Unfortunately, the drilling engineer still must define the planning parameters that can be relaxed or modified when drilling normal-pressure holes or well types such as step-outs or infills.
Section 2.0: Literature Review
The most important aspect of preparing the well plan, and subsequent drilling engineering, is determining the expected characteristics and problems to be encountered in the well. The proposed vertical exploratory well in the newly licensed Gordon-X field cannot be planned properly if these environments are unknown. Therefore, the drilling engineer must initially pursue various types of data to gain insight used to develop the projected drilling conditions.
Section 2.1: Offset-Well Selection:
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The drilling engineer is usually not responsible for selecting well sites. However, he must work with the geologist for the following reasons:
Develop an understanding of the expected drilling geology. Define fault-block structures to help select offset wells similar in nature to the
prospect well. Identify geological anomalies as they may be encountered in drilling the
prospect well.
A close working relationship between drilling and geology groups can be the difference between a producer and an abandoned well.
Section 2.2: Data Sources
Data sources should be available for virtually every well drilled in the newly licensed Gordon-X field. Drilling costs prohibit the rank wildcatting that occurred years ago. Although wildcats are currently being drilled, seismic data, as a minimum, should be available for pore-pressure estimation. Common data types used by the drilling engineer are listed next:
Bit mud mud-logging, and Operator’s drilling records. Drilling reports from operators or the Intl. Assn. of Drilling Contractors
(IADC). Scout tickets. Log headers. Production history. Seismic studies. Well surveys. Geological contours. Databases of service company files.
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Each record contains data that may not be available with other sources. For example, log headers and seismic work are useful, particularly if these data are the only available sources.
Many data sources exist in the industry. Some operators consider the records confidential, when in fact the important information, such as well-testing and production data, becomes public domain a short time after the well is completed. The drilling engineer must assume the role of "detective" to define and locate the required data.
Data sources include bit manufacturers and mud companies who regularly record pertinent information on well recaps. Bit and mud companies usually make these data available to the operator. Log libraries provide log headers and scout tickets. Internal company files often contain drilling reports, IADC reports, and mud logs. Many operators share old offset information if they have no further leasing interest.
Bit Records:
An excellent source of offset drilling information is the bit record. It contains data relative to the actual on-bottom drilling operation. The heading of the bit record provides information such as the operator, contractor, rig number, well location, drill string characteristics, and pump data. In addition, the bit heading provides dates for spud-ding, drilling out from under the surface casing, intermediate-casing depth, and reaching the hole-bottom.
The main body of the bit record provides the number and type of bits, jet sizes, footage and drill rates per bit, bit weight and rotary operating conditions, hole deviation, pump data, mud properties, dull-bit grading, and comments. The vertical deviation is useful in detecting potential dogleg problems.
Comments throughout the various bit runs are informative. Typical notes such as "stuck pipe" and washout in drill string can explain drilling times greater than expected. Drilling engineers often consider the comments section on bit (and mud) records to be as important as the information in the main body of the record.
Bit-grading data can be valuable if the operator assumes the observed data are correct and representative of the actual bit condition. The bit grades assist in
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preparation of a bit program identifying the most (and least) successful bits in the area. Bit running problems such as broken teeth, gauge wear, and premature failures can be observed, and preventive measures can be formulated for the new well.
Drilling Analysis: Bit records can provide additional useful data if the raw information is analyzed. Plots can be prepared that detect lithology changes and trends. Cost-per-foot analyses can be made. Crude, but often useful, pore-pressure plots can be prepared. Raw drill-rate data from a well and an area can detect trends and anomalies. Cost-per-foot studies are useful in defining optimum, minimum-cost drilling conditions. A cost comparison of each bit run on all available wells in the area will identify bits and operating conditions for minimum drilling costs. The drilling engineer provides his expected rig costs, bit costs, and assumed average trip times. The cost-per-foot calculations are completed with Eq. 11.1.
...............................................................[Eq. 1.0]
A cost-per-foot analysis is illustrated by Fig 3.0 below:
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Fig. 3: Cost per foot for the bit run
Trip times should be averaged for various depth intervals. Several operators have conducted field studies to develop trip-time relationships (Table 2.0 below). The most significant factors affecting trip time include depth and hole geometry (i.e., number and size of collars, and down hole tools). Table 2.0 given below can be used in the cost-per-foot equation (Eq. 1.0) analysis.
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Table 2.0: A typical average trip times (illustration purpose only)
Mud Records:
Drilling-mud records describe the physical and chemical characteristics of mud system. The reports are usually prepared daily. In addition to the mud data, hole and drilling conditions can be inferred. Most personnel believe this record is important and useful.
Mud engineers usually prepare a daily mud-check report form. Copies are distributed to the operator and drilling contractor. The form contains current drilling data such as well depth, bit size and number, pit volume, pump data, solids-control equipment, and drill string data. The report also contains mud-properties data such as mud weight; pH; funnel viscosity; plastic viscosity; yield point; gel strength; chloride, calcium, and solids content; cat ion-exchange capacity; and fluid loss.
An analysis of these characteristics taken in the context of the drilling conditions can provide clues to possible hole problems or changes in the drilling environment. For example, an unusual increase in the yield point, water loss, and chloride content suggests that salt (or salt water) has contaminated a freshwater mud. If kick-control problems had not been encountered, it is probable that salt zones were drilled. A
23
composite mud recap form is usually prepared. It contains a daily properties summary. It may also include comments pertaining to hole problems.
Daily reports prepared by the mud engineer are useful in generating depths-vs.-days plots (Fig. 4.0 below). These plots are as important to well-cost estimating as pore pressures are to the overall well plan. Other types of records (i.e., bit records and log headers) do not provide sufficient daily detail to construct the plot as accurately as mud records.
Fig 4: Depth vs. days plot developed from a mud record (for illustration purpose only).
IADC Reports:
The drilling contractor maintains a daily log of the drilling operations recorded on the standard IADC-API report. It contains hourly reports for drilling operations, drill string characteristics, mud properties, bit performance, and time breakdowns for all
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operations. These reports are usually unavailable to other contractors or operators and, as a result, cannot be obtained for offset-well analysis without the operator ’ s cooperation.
Scout Tickets:
Scout tickets have been available as a commercial service for many years. The tickets were originally prepared by oil company representatives who "scouted" operations of other oil companies. Current scout tickets contain a brief summary of the well. The data usually include:
Well name, location, and operator. Spud and completion dates. Casing geometries and cement volumes. Production-test data. Completion information. Tops of various geological zones.
The data source for scout tickets are the state or federal report forms filed by oil companies during the course of drilling the well.
Fig. 5: A typical scout ticket (for illustration purpose only)
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Mud-Logging Records:
A mud log is a foot-by-foot record of drilling, mud, and formation parameters. Mud-logging units are often used on high-pressure or troublesome wells. Many engineers consider the mud log to be the best source of penetration-rate data. Mud logging records are seldom available to groups other than the well operators.
A section of a mud log is shown in Fig. 5.0 below. Drilling parameters normally included are penetration rate, bit weight and rotary speed, bit number and type, and rotary torque.
Fig 6: A typical section of a mud log (for illustration purpose only)
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Mud-logging scales are often arranged so the drill-rate curve can be compared to the spontaneous potential (SP) or gamma ray curve on offset logs. The mud log may contain drilling-related parameters such as mud temperatures; chlorides; gas content in the mud and cuttings, usually measured in ’ units’ lithology; and pore-pressure analysis. The pore pressure can be computed from models such as the d-exponent or other proprietary equations or can be measured by drillstem tests.
Log Headers:
Drilling records similar to the previously described information are not available on all offset wells. In these cases, log headers can yield useful drilling data. Easily attainable data from the log headers include logging depths, mud weight and viscosity at each logging depth, bit sizes, inferred casing sizes, and actual setting depths. If enough logging runs were made, a useful depth-vs.-days plot can be constructed.
Production History:
Production records in the offset area can provide clues to problems that may be encountered in the prospect well. Oil/gas production can reduce the formation pressure and cause differential pipe sticking. Production records provide pressure data from the flowing zones. Unfortunately, pressures in the over- and underlying formations will not change appreciably. This obscures detection with drilling parameters.
Seismic Studies:
Wildcat wells are seldom drilled without preliminary seismic work being done in the area. Analysis of seismic reflections can eliminate the "wildcat" status of the well by predicting pore pressures. Several authors have shown that good agreement on the pore pressures can be attained with seismic and sonic-log data.
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Section 3.0: MAIN REPORT ANALYSIS
Section 3.1: Importance of pore and fracture pressures when planning a well
The importance of pore and fracture pressures with respect to safely planning the new vertical exploratory well in the newly licensed Gordon-X field cannot be over-emphasized. Accurate prediction of the sub-surface pore pressures and fracture gradients is a necessary requirement for safe, economical and efficient drilling of the wells required to explore and produce oil and natural gas reserves. Fracture pressure can be defined as pressure needed to cause a formation to fail or split. As the name implies, it is the pressure that causes the formation to fracture and the circulating fluid to be lost. Fracture pressure is usually expressed as a gradient, with the common units being psi/ft (kPa/m) or ppg (kg/m3). To fracture a formation, three things are generally needed, which are:
Pump into the formation. This will require a pressure in the wellbore greater than formation pressure.
The pressure in the wellbore must also exceed the rock matrix strength. And finally the wellbore pressure must be greater than one of the three
principal stresses in the formation
One of the most important parameters to determine the reliability and success of a casing design is the pore pressure. Clear interpretation of the formation pressure is needed for the drilling plan to choose casing points and to design a casing that allows the well to be drilled effectively and maintain well control during drilling and completion operations. If accurate pore and fracture gradients are used at the design stage well control events such as fluid kicks, lost circulation, surface blowouts and underground blowouts can be prevented.
Section 3.2: Determination of pore pressures
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From available data on the proposed new vertical exploratory well in the newly licensed Gordon-X field. We have:
Pore Pressure Data:
The following are the initial pore pressure predictions:
Surface to 4 000 ft normal pressure – 8.9 ppg EMW (EMW)
At 9 000 ft the pore pressure is expected to have risen to 10.5 ppg (EMW)
From 9 000 ft to TD the pore pressure is constant at 10.5 ppg EMW
Y-AXIS [DEPTH] ft
X-AXIS [EMW] ppg
4000 8.99000 10.5
11750 10.5
EMW [ppg] = Pore Pressure [psi]/0.052XDepth [ft]……………………………………..[Eq. 2.0]
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. ͦ. Pore Pressure, Pp = 0.052X EMW [ppg] X DEPTH [ft]……………………………[Eq. 3.0]
@ 4000ft and 8.9ppg [EMW], Pore Pressure [Pp] = 0.052 x 8.9 x 4000 = 1851psi
@ 9000ft and 10.5ppg [EMW], Pore Pressure [Pp] = 0.052 x 10.5 x 9000 = 4914psi
@11750ft & 10.5ppg [EMW], Pore Pressure [Pp] = 0.052 x 10.5 x 11750= 6416psi
Section 3.3: Typical Mud System and its relevant components/functions
Planning the proposed vertical exploratory well in the newly licensed Gordon-X field will not be complete without discussing its mud system and her relevant sections/components. Different Sections of surface mud systems includes:
Removal Section: Separation of undesirable drilled solids and even gas occurs in this section.
Addition Section: Commercial chemicals are being added and agitated to control and condition the mud.
Suction and Testing Section: This is the last part of the mud systems wherein evaluation and testing procedures are conducted before re-circulating the fluid to down hole.
Major Components of the Mud System and their functions are:
Mud Gas Separator: It captures and separates large volume of free gas within the drilling fluid.
Shale shakers: Used to remove large solids (cuttings) from the drilling fluid ("Mud").
Sand Trap: Its function is to prevent sand and mud from entering mud systems.
De-sander: Remove sand particles from the drilling fluid. De-silter: Remove silts from the drilling fluid.
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Degasser: Used in drilling to remove gasses from drilling fluid Mud cleaner: The purpose of the mud cleaner is to remove drilled solids
larger than barite. Decanting Centrifuge: Separates solid materials from liquids in slurry Mud agitator: Used in surface mud systems to suspend solids and maintain
homogeneous mixture throughout the system Tanks/Compartments: Its main function is to remove large solids that might
plug the downstream system. Mud Guns: Used for mixing drilling mud in the circulatory system and to
prevent the mud from precipitating. Mixing Hopper: For mixing of both mud bulk material and mud additive
chemicals into the drilling fluid. Centrifugal Pumps: Used to transfer drilling mud to make it circulate through
tank system. Mud Pumps: A large pump used to move heavy drilling fluid, known as mud.
Its purpose is to float rock cuttings out of the hole, clean the bottom of the hole out.
Other sub-components include:
[i] Screw Conveyor
[ii] Mud Ditch
[iii] Trip Tank
[iv] Water Tanks
[v] Atmospheric Degasser
[vi] Cutting Driers
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Fig 7: Layout of a typical drilling mud system
Section 3.4: Determination of Mud Pit Capacity
From available data on the proposed new vertical exploratory well in the newly licensed Gordon-X field. We have:
Casing Data:
The proposed casing used is as follows:
20” surface casing set at 550ft below GL with casing weight of 133 lb/ft, 13 3/8” intermediate casing set at 4,000ft below GL with casing weight of 72 lb/ft, 9 5/8” production casing set at 10,000ft below GL with casing weight of 54.5 lb/ft, 7” production liner set at 12,000ft below GL.
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Fig 8: Open Hole Calculation design schematics
Casing or Open Hole Capacity = [I.D]²/1029.4 bbl/ft ……………………………… [Eq. 4.0]
Casing or Open Hole Volume = Casing/Open Hole Capacity x TVD ……..… [Eq. 5.0]
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Mud Pit Capacity = Casing Volume + Open Hole Volume [plus open hole excess]……………………………………………………………………………………………….………..[Eq. 6.0]
Considering 17.5” Open Hole:
Casing Capacity = [19.12] ²/1029.4 = 0.355bbl/ft
Casing Volume = 0.355 x 550ft = 195.3bbls
Open Hole Capacity = [17.5] ²/1029.4 = 0.298bbl/ft
Open Hole Volume = 0.298 x 3450ft = 1028bbls
50% Open Hole Excess = 0.5 x 1028bbl = 514bbls
Total Open Hole Volume = [514 + 1028]bbls = 1542bbls
Mud Pit Capacity @ 4000ft = [195.3 + 1542]bbls = 1737 bbls
Considering 12.25” Open Hole:
Casing Capacity = [12.415] ²/1029.4 =0.150bbl/ft
Casing Volume = 0.150 x 4000 = 598.9 bbls
Open Hole Capacity = [12.25] ²/1029.4 = 0.146bbl/ft
Open Hole Volume = 0.146 x 6000 = 876 bbls
25% Open Hole Excess = 0.25 x 876 = 219bbls
Total Open Hole Volume = [219 + 876]bbls = 1095bbls
Mud Pit Capacity = [598.9 + 1095]bbls = 1693.9bbls
Considering 8.5” Open Hole:
Casing Capacity = [8.681] ²/1029.4 = 0.073bbl/ft
Casing Volume = 0.073 x 10000 = 730bbls
Open Hole Capacity = [8.5] ²/1029.4 = 0.070bb/ft
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Open Hole Volume = 0.070 x 2000 = 140bbls
10% Open Hole Excess = 0.1 x 140 = 14bbls
Total Open Hole Volume = [14 + 140]bbls = 154bbls
Mud Pit Capacity = [154 + 730]bbls = 884bbls
Hence,
Total Mud Pit Capacity = [1737 + 884 + 1693]bbls = 4316bbls
Section 3.5: Gas Ingress While Drilling and Steps to be
Taken to Regain Control of the Well
Gas ingress while drilling:
When primary well control has been lost and gas enters the well bore, a hydrostatic overbalance is no longer maintained. Instead, we have a pressure balance in the annulus between the formation pressure and the sum of the hydrostatic heads of the fluids in the annulus plus viscous frictional losses due to flow plus the back pressure applied at the surface. If no, or insufficient back pressure is applied the rate of flow from formation to well will increase until the frictional losses in the annulus enable equilibrium to be reached. The result is a blow-out caused by ingress of gas into the well bore.
Steps to be taken to regain control of the well again:
The pressure balance should be maintained in static conditions by closing off the annulus at the surface by means of BOPs. Flow will then only continue until the well head pressure has increased to the difference between the formation pressure and the hydrostatic pressure of the fluid column in the annulus.
Under dynamic conditions (i.e. during the well killing operations) the balance is maintained and additional inflow is prevented by applying a calculated back pressure which is equal to the formation pressure minus the hydrostatic head in the annulus minus the frictional losses plus a safety factor.
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Given that the hydrostatic head in the annulus will vary as the initial volume of gas ingress flows up the well, and as kill mud is pumped down the drill pipe and enters the annulus, it is necessary to vary the applied back pressure. This is done by passing the flow through a restriction [adjustable choke] whose size can be changed in a quantifiable manner.
Section 3.6: Functions of the Units that Comprise a Typical
Blow-Out Preventer
What are Blow-out preventers (BOPs)?
A blowout preventer is a large, specialized valve or similar mechanical device, usually installed redundantly in stacks, used to seal, control and monitor oil and gas wells. Blowout preventers were developed to cope with extreme erratic pressures and uncontrolled flow (formation kick) emanating from a well reservoir during drilling. Kicks can lead to a potentially catastrophic event known as a blowout.
Basic units of BOPs and its functions [Ram-type]:
Pipe rams close around a drill pipe, restricting flow in the annulus (ring-shaped space between concentric objects) between the outside of the drill pipe and the wellbore, but do not obstruct flow within the drill pipe. Variable-bore pipe rams can accommodate tubing in a wider range of outside diameters than standard pipe rams, but typically with some loss of pressure capacity and longevity.
Blind rams (also known as sealing rams), which have no openings for tubing, can close off the well when the well does not contain a drill string or other tubing, and seal it.
Shear rams cut through the drill string or casing with hardened steel shears.
Blind shear rams (also known as shear seal rams, or sealing shear rams) are intended to seal a wellbore, even when the bore is occupied by a drill string, by
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cutting through the drill string as the rams close off the well. The upper portion of the severed drill string is freed from the ram, while the lower portion may be crimped and the “fish tail” captured to hang the drill string off the BOP.
Section 3.7: Down-hole Equipment Design for the Well
Below is detailed information on reservoirs in the newly licensed Gordon-X field.
There are two reservoirs:
Reservoir A: At 10,500ft to 10600ft. It is a gas reservoir containing basically methane with a gas gradient of 0.12 psi/ft. As there is no means of evacuating(exporting) any gas produced until an electric power station is constructed to use the gas as fuel the gas reservoir will not initially be produced.
Reservoir B: At 11000ft to 11750ft. This is the primary oil reservoir, and will provide the initial production from the field.
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Fig 9: The Exploratory Well design schematics based on given data
Analysis based on applicable equations and standard/given data:
Our further analysis and design shall be centered on reservoir B which is the primary oil reservoir and is intended to provide the initial primary production from the field.
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We shall be analyzing and applying the given data for the new vertical exploratory well proposed in the newly licensed Gordon-X field based on the below information with applicable equations and standard data tables.
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Table 3.0: API Drill Pipe Grade US customary unit
Table 4.0: API Drill Pipe Grade SI unit
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Pressure Calculation:
At a Total Depth [TD] of 11750ft and Mud Weight of 10.5ppg
Pressure exerted, P = 0.052 x Mud Weight x TD
P = 0.052 X 10.5 X 11750 = 6416psi
Drill String and BHA Calculations:
Buoyancy Factor [BF] of mud weight
BF = 1 – [10.5/65.5] = 0.8397
Collar Length needed to achieve desired weight on bit [WOB]:
WOB = 50kips, Safety Factor = 0.85 (since well and field is new)
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Drill Collar weight (8 in x 3 in) = 147lb/ft
Assumed Stiffness Ratio [SR] = 3.5 ( severe drilling)
Length of BHA, LBHA = 50 X 1000/ [0.85 X 0.8397 X 147] = 476.6ft
LBHA is approx. 477ft
Maximum Length of Drill Pipe needed with BHA is given by:
…………………………………..…………[Eq. 7.0]
Where:
Lmax = maximum length of drill pipe that can be run into the hole with a specific BHA in feet,
TS = tensile strength for new drill pipe in lb,
fdp = safety factor to correct new drill pipe to no. 2 pipe,
MOP = margin of over- pull in lb,
WBHA = weight of the BHA in lb,
Wdp = weight of drill pipe with tool joint in lb/ft.
Drill Pipe to be used = G105 at 19.5lb/ft
Tensile Strength of new pipe = 553,800lb [TS]
Safety Factor to correct drill pipe to no. 2 pipes = 10% [Fdp]
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Assumed Desired Over-pull = 100,000lb [MOP]
Weight of BHA = 50,000lb [WBHA]
BHA Length = 477ft [LBHA]
Weight of drill pipe with tool joint = 19.5lb/ft [Wdp]
Buoyancy Factor = 0.8397 [BF]
Hence,
Maximum Length of Drill Pipe needed with the BHA is:
Lmax = [[553,800(1 - 0.1) – 100,000 – 50,000] x 0.8397]/19.5] = 15,003.5ft
Max. Length of Drill Pipe, Lmax is approx. 15,004ft
Total Depth that can be Reached with a Specific BHA in ft:
………………………………………………….……[Eq. 8.0]
Where:DT = total depth that can be reached with a specific BHA in ft,LBHA = length of BHA to be run in ft
Hence,
DT = [15,004 + 477]ft = 15,481ft
Assume: 1 drill Collar joint = 30ft
Then,
Number of Drill Collars [DC’s] needed to make up the BHA is given by:
LBHA [ft] / 30 [ft] = 477 / 30 = 15.9
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Therefore, we will need approx. 16 DC’s plus 1 jar and an additional 2 DC’s [just in case]. Hence, the BHA will be made up of 19 units.
BHA Design consists of:
18 Drill Pipes
1 Drill Jar
3 Stabilizers
1 Float Sub
Fig. 10: BHA Design representation
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Section 4.0: Summary/Conclusion
The costs required to plan this new vertical exploratory well properly are insignificant in comparison to the actual drilling costs. In many cases, less than U.S. $1,000 is spent in planning a well with a drilling cost of over U.S. $1 million. This represents 1/10 of 1%; of the well costs.
Unfortunately, many historical instances can be used to demonstrate that well planning costs were sacrificed or avoided in an effort to be cost conscious. The end result often is a final well cost that exceeds the amount required to drill the well if proper planning had been exercised. Perhaps the most common attempted shortcut is to minimize data-collection work. Although good data can normally be obtained for small sums, many well plans are generated without the knowledge of possible drilling problems. This lack of expenditure in the early stages of the planning process generally results in higher-than-anticipated drilling costs.
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Section 5.0: References
Fundamentals of Onshore DrillingBy Martin Klempa & Co
Shell IWCF training manual Well Engineering and Construction
By Hussain Rabia Internet
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