Drilling and Completion

7/27/2019 Drilling and Completion

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Geological studies and seismic surveys can point the way to ahydrocarbon prospect. But there is only one way to know if thatprospect contains oil or gas, and that is to drill a well.

Drilling projects are team undertakings. They encompass a widerange of disciplines and job functions, from geology, geophysicsand engineering to operations, support and logistics, safety and

regulatory compliance, management and administration. Projectteams are often part of alliances that include:

The oil or gas company (also known as theoperating company oroperator), along with anyjoint venture partners having an interest in the well;

An outside drilling contractorwho provides thedrilling rig and the personnel to run it; and

One or more service companies that providespecialized equipment and expertise at variousstages of the project. The largest of these servicecompanies may offer integrated project managementservices that include contract drilling.

The working relationships that characterize a drilling projectdepend on the well's location, the arrangements between thecompanies involved in the project and the number of personnelinvolved. A small onshore rig may be crewed by no more than fivecontractor employees and managed by just one or two contractorand operator representatives, while some large offshore drillingoperations may have several rig crews and groups of specialiststotaling 50 or more persons, along with dozens of land-basedtechnical and support personnel.

Drilling Objectives

However they might differ in other respects, all drilling operationshave three basic objectives:

1. Drill safely. Health, safety and environmental (HSE)considerations supersede all other goals, even ifthey require changing plans, delaying operations orincurring extra costs.

2. Provide a fit-for-use well. Whether it is drilled forexploration, prospect appraisal or field development,a well must meet the needs that led to it beingproposed in the first place. As a minimum standard,it should be drilled without damaging the borehole orany potential producing formations, and it should

satisfy the design requirements for formation testing,data gathering, oil and gas production or other post-drilling activities.

3. Minimize overall well cost. It is therefore ineveryone's interest to control well costs. In thiscontext, it is important to consider the total cost overthe life of the well, and to balance this cost againstthe first two objectives of safety and well usability. Anoffshore well in West Coast of Africa may cost up to30 times higher than an average onshore well in the


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US. Since drilling is the most expensive componentof the entire exploration and field developmentprocess, the oil&gas industry pays a lot of attentionto improve drilling efficiency and cut drilling time inorder to control well costs.

Surface and Subsurface EnvironmentsAny area that produces oil or gasor has the potential for doingso in the futureis a likely location for a drilling rig. Rigs come in avariety of configurations and designs for surface environments thatrange from Arctic to desert, ocean to mid-continent and just abouteverything in between (Figure 1).

Figure 1:Drilling operations must adapt to a wide range of surface environments. These are just a fewexamples.

While drilling rigs often work in remote locations, they may also befound in settled or even urban areas, as shown in Figure 2.


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Figure 2:

Rig operations in Los Angeles, California. The rig in the top photograph is working at the San

Vicente Drill site near Beverly Hills the wall next to the rig is part of a shopping mall. The two rigsin the bottom photograph are being used to abandon old wells at the Farmer's Market Drill Site. Ifyou look very closely, you can see a patch of white on the hill in the background this is the famousHollywood sign, an L.A. landmark for many years (State of California, 2005).

Most drilling rigs operate 24 hours per day, 7 days per week. Rigcrews work 8 or 12-hour shifts ortours (pronounced towers), inrotations that last anywhere from one to four weeks or more,depending on the location.

The subsurface conditions that drilling crews encounter are asvaried as their hours and work locations. The total depth ( TD) of awell may be anywhere from a few hundred to more than 20,000feet. It may be possible to reach TD by drilling straight down, or it

may be necessary--and sometimes beneficialto drill part of thewell at an angle or even horizontally. Along the way, there mightbe any number of rock types, including loose gravel, soft, stickyclay or shale, abrasive sandstone, hard carbonates and even salt.Each rock type presents its own set of challenges. Subsurfacepressures may range from a few hundred at the surface to 5000,10,000 or even 20,000 pounds per square inch ("psi") at deeperdepths. In some wells it is not always easy to predict the expectedpressure level. Temperatures may likewise range from near-


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surface conditions to 400 F [200 C] or more. And there is oftena good chance of encountering toxic or corrosive gases.

Before drilling even begins, a project team has to plan what willhappen after TD is reached whether it will be completed as aproducing well or abandoned and how the well will fit into overallreservoir management objectives. These and other considerations

will affect project planning, well design and drilling operations.

Rig Counts

When business analysts want to get a feel for the oil and gasindustry, they often look at rig counts such as the ones publishedweekly and monthly by Baker Hughes(http://www.bakerhughes.com/investor/rig/). These provide current andhistorical data on the number of drilling rigs working in variousparts of the world. This information is valuable because the drillingsector, being at the leading edge of oil and gas developmentactivity, is particularly sensitive to such factors as oil pricefluctuations and economic conditions of the industry (Figure 3).

Figure 3:Worldwide drilling rig count, 1980-2011 (YTD) (Baker-Hughes Inc.). Note the correlation between rigcount and spot oil price (price data from BP Statistical Review of World Energy, 2011 and EIA).

In January 2011, there were 2,180 rigs operating in differentregions (Figure 4). More than half of them were busy drilling

natural gas wells in the US and Canada (Baker-Hughes, 2011).
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Figure 4:

Worldwide drilling rig count by region (Baker-Hughes Inc., 2011).

At the end of this module, under the headingAdditionalResources,you will find a list of Web resources that will help youtrack rig activity and give you some useful general informationabout the drilling industry.

Drilling Technology

Virtually all oil and gas wells today are drilled using the rotarymethod, in which rock is broken into small particles orcuttingsunder the weight applied to a rotating drill bit (Figure 5).


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Figure 5: Rotary Drill Bits:

These and many other bit types are each designed for certain kinds of rock formations, and eachhas its ideal area of application.

The bit is made up on (i.e., screwed into) the end of a drill string,which consists of individual lengths orjoints of hollow steel pipeabout 30 feet long (Figure 5). The drilling rig, acting as a type ofhoist, lowers the pipe into the well. Each time the bit drills theequivalent of one pipe length, drilling is stopped while another jointof pipe is added to the stringa procedure is known as making aconnection. In this way, the well is eventually drilled to TD.

As the bit drills ahead, a specially formulated drilling fluid ormudis continually pumped orcirculatedfrom the surface, to the bottomof the well, and then back to surface to cool the bit and remove thecuttings (Figure 6).


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Figure 6:

Circulation of the drilling fluid from the mud pit to the mud pump, through the rotary hose, downthe drill string, and up the annular space to the surface, where the cuttings are removed and themud is treated and returned to the mud pit.

Although rotary drilling techniques came into their own over ahundred years ago, the technologies used to apply them haveevolved dramatically within the past decade. Formations that a few

years ago would have been unreachable are now targeted almostroutinely, and wells that once would have taken months to drill arecompleted in a matter of weeks at a fraction of the cost. We willidentify some of these technologies as we proceed through thismodule.

Phases of Well Construction

Well drilling and completion involves a number of distinct projectfunctions. Companies may differ as to who is primarily responsiblefor each function, and where one function ends and anotherbegins, but one good breakdown would be as follows:

Well Planning Well Design

Drilling Operations

Formation Evaluation and Testing

Well Completion

Note: For simplicitys sake, this discussion and itsaccompanying Case Study examine the drillingand completion process as it relates to a single


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well. In reality, most projectsparticularly thoserelating to field developmentare based ondrilling multiple wells, and project budgets, drillingcontracts, regulatory requirements and so forthare developed in this "multi-well" context.

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Well Planning

Initial Steps

Well planning typically begins when the operating company'sexploration or development geologists generate a well proposal.This document specifies the well classification (Exploration,Appraisal or Development), describes the proposed target locationand outlines specific drilling objectives. It is generally followed upwith a preliminary economic analysis.

If management (including any joint venture partners) accepts theproposal, the next step is to prepare a drilling program. The drillingprogram presents a geological prognosis of the formations to beencountered, their anticipated subsurface conditions, and a set ofwell design parameters. It outlines the drilling procedures andformation evaluation requirements, and specifies a date by whichoperations should commence.

Along with the drilling program, the project team prepares a detailedcost estimate. This is based, where possible, on past performancein the same or similar areas, and on current costs of drillingmaterials, products and services. For onshore exploration wells, theestimate will be broken down into dry hole costs, in the eventresources are not discovered, as well as the completion cost if thewell results in a discovery.

For many years, these initial steps and those that followed involvedlong, laborious processes of data collection, compilation andanalysis. As drilling environments became more complex, this

process threatened to become overwhelming. Fortunately, it hasbeen streamlined in recent years with the advent of database andknowledge management software (e.g., Landmark (2006), IHSEnergy (2006) that enables project teams to compile informationfrom a range of sources, generate reports and analyze large volumeof data in time frames that would have been impossible previously.These resources have proven invaluable in both well planning andoperations.
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Authorization for Expenditure (AFE)

An Authorization for Expenditure, orAFE, summarizes thecomplete drilling plan and expected cost. It gives a line-by-linebreakdown of individual component costs. It is then reviewed by,approved and executed by all parties participating in the drilling ofthe well. A typical AFE for an onshore exploration well is shown inExhibit 1

Exhibit 1

Management approval of the AFE represents approval of its statedobjectives and the estimated cost to meet those objectives. Becauseof the uncertainties encountered during drilling, all of the participantsare aware that costs may rise above the AFE amount.

After an AFE is approved, the project takes on a new perspective.The geologists and engineers who defined the prospect,documented its potential value and prepared a package formanagement approval now turn the project over to the drillingengineers for preparation of the detailed well design and operating

procedures.

Environmental and RegulatoryConsiderations

There are usually one or more government agencies that regulateand control drilling operations. They generally involveenvironmental, safety and other issues. Failure to adhere to thesestipulations or obtain the necessary permits in time can delay orshut down drilling operations, and can result in severe civil or evencriminal penalties. An operating company typically has a staff ofadvisors who assist drilling personnel in complying with theseregulations and submitting applications for drilling permits. The

operator's loss-prevention/safety advisor should also assist incomplying with inspections. The operator usually posts a substantialbond (often millions of dollars) to be used if drilling or environmentalregulations are violated.

Support and Logistics

The support and logistical issues that occupy drillingsuperintendents in Nigeria will be quite different from those thatconcern their counterparts in West Texas (or, for that matter, otherparts of West Africa). Every onshore or offshore location has its ownset of considerations regarding supply point proximity, personnelavailability, transportation infrastructure, communications, weather,labor relations, political stability and other issues.

Drilling Rig Procurement

The drilling contract, although separate from the well plan, is anintegral part of the logistics of the well plan. It is typically the drillingdepartment's job to provide rig specifications for the bid request,check the condition of the rig equipment and assist in setting up abid list of contractors with satisfactory performance records.
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Rig specifications ensure that the rig obtained is satisfactory forthe well being drilled, based on requirements developed in the wellplan, and that there is a "common ground" for evaluating bids.

The bid document should provide sufficient information for biddersto respond to the job being bid, and should pave the way fornegotiating a drilling contract with the winning bidder. At minimum, it

should include the following information:

The expected depth of the well(s) and the number ofwells;

Anticipated drilling difficulties;

Specific equipment requirements and any unusualoperating requirements; and

Services and equipment to be provided by theoperator.

Bid requests generally contain language that reserves the operator'sright to return all bids unopened, reject all bids or award the contractto other than the lowest bidder. The invitation to bid requests thefollowing information:

Rig specifications and equipment inventory;

Rig location;

Rates of pay for which the rig and all its equipment areoffered under different conditions, such as operatingrate, break-down rate, force majeure rate, standby rateand mobilization/demobilization cost;

Specific details of any special contract terms that thecontractor insists upon, and which affect the operator'scosts or liabilities; and

The bid request should note any special contractual

provisions that might affect the contractor's bid,including insurance requirements or other terms thatmight affect the contractor's costs.

Once bids are submitted, the operating company's contractcommittee does a quick check to verify that the bidders havefollowed instructions. A subsequent detailed analysis will determinewho offers the optimal equipment at a price that will result in themost economic well(s), and with contract terms acceptable to theoperator.

If none of the bids meets the operator's requirements, a waiverletteris prepared detailing the specifics of the operator'sdissatisfaction with the bids and recommending that the bid

procedure be waived in favor of direct negotiation for a rig with oneor more acceptable contractor(s).

Once a contractor is selected, the operator and the contractor mustnegotiate a mutually satisfactory contract often starting fromindustry standard forms.

Throughout this process, it is important for the operator to look pastthe obvious (e.g., rig equipment specifications, contract rates, etc.)and consider other questions. For example, what percentage of the


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time that the contractor has spent at various locations has involveddowntime for rig repairs, lost-time accidents or other non-productive hours? How well maintained is the rig? How experiencedare the rig crews? What types of training and certifications do theyhave? Has the contractor been cited for non-compliance with safetyor environmental regulations? These and other considerationsshould play a major part in evaluating bids and negotiating acontract.

Drilling Contracts

The principal drilling contract compensation arrangements are dayrate, footage and turnkey. Figure 7 summarizes their mainprovisions.

Figure 7:Principal drilling contract arrangements.

Each arrangement has certain advantages and disadvantages forboth the operator and the drilling contractor. A day rate contractgives the operator more control over drilling procedures, butprovides fewer incentives for the contractor to drill faster and finishthe well. A footage contract, on the other hand, gets the well drilledmore quickly, but handicaps the operator with respect to suggestingimprovements in drilling practices.


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One way of making these arrangements mutually beneficial is tocombine themfor instance, by going to a combination day-rate/footage contract, where a well is drilled on a footage bid to aspecified depth, and then switched over to a day rate for the deeper,more risky drilling. In this case, the contractor avoids the greaterrisks involved in deeper drilling, while the operator gets control overa critical phase of the operation. Thus, both the operator andcontractor are continually interested in maximizing drilling efficiency.

The type of drilling contract used depends in part on the market fordrilling rigs. When rigs are in short supply, contractors are moreparticular about assuming technical and economic risks, and arelikely to prefer a day rate contract. When there is an oversupply ofrigs and contractors are anxious for work, they are more willing tobid turnkey and absorb the risk (in some respects, this turnkeyarrangement is a convenience to the operating company,particularly if it has a small drilling staff).

Well DesignIn general (and with numerous exceptions), the deeper the well, themore challenging and expensive it is to drill. This is due to theincreasing variety and hardness of the formations encountered, the

higher stresses on pipe, rig systems and other equipment, and thefact that the changing of bits takes longer and that both pressureand temperature usually increase with depth.

Subsurface Pressure and Temperature

The pressure of the formation fluids contained within a rock's porespaces is known as the pore pressure. The rate at which thispressure increases with depththe pore pressure gradient

depends on the density of the fluids. For example:

The density of the salt water found in the formations ofthe US Gulf Coast is around 67 pounds per cubic foot

(compared to 62.4 pounds per cubic foot for freshwater).

Under normal conditions, where the formation water isin hydraulic communication with the surface, the porepressure gradient is 0.465 psi per foot.

Thus, the pore pressure in this area at a depth of10,000 feet would be:

0.465 psi/ft x 10,000 ft = 4650 psi
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Anticipating and controlling pore pressures is an overridingconsideration in drilling projects. In many areas, geological orgeochemical processes can affect the pore pressure gradient,causing it to deviate from its normal trend and resulting in abnormalpressures that are higher or lower than expected. Figure 8 showsthe normal fluid pressure gradient for a group of US Gulf CoastFields and the actual measured pressures, which are higher thannormal. At normal fluid pressure gradient the formation pressure iscaused by the weight of continuous column of water to the surface.At the lithostatic pressure gradient the formation pressure is causedby the weight of the rock formation to the surface.


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Figure 8:Deviation from the normal pressure trend measured in a group of US Gulf Coast oilfields (Levorsen,1967. Courtesy W.H. Freeman and Co.)

Subsurface temperatures do not usually impact operations as muchas subsurface pressures, although high temperatures can influenceboth the equipment and procedures used to drill the well.

Temperature, like pressure, increases with depth. Depending on thearea, the increase can range from one to five degrees Fahrenheitper 100 feet; a typical range is between 1.4 and 2 F per 100 feet.Thus, a 10,000-foot well in an area where the surface temperatureaverages 60 F might have a bottomhole temperature of around200 F.

Hole Sections

Wells are rarely drilled in one continuous interval from surface totarget depth. Rather, they are drilled in two or more hole sections.Each section is drilled and if the evaluation indicates that drillingshould continue, then a specially designed and fabricated steel pipecalled casing is placed and cemented into the well to seal off theinterval. Casing comes in a variety of sizes and strengths towithstand different formation pressures and temperatures. Part ofthe well design process involves selecting the appropriate casing fora given hole section.

Once the casing is cemented in place, the next hole section isdrilled, and so on to Total Depth, or TD.

The first major string of casing in a well is usually run to preventshallow formations from caving in, to protect them from the higherwellbore and formation pressures that are likely to be encounteredat greater depths, and to isolate any fresh water sands that may bepresent. Additional casing strings may be needed before reachingTD, depending on the well's depth and formation characteristics.Upon reaching the target formation is evaluated and, if the resultsare favorable, the production string of casing will be ran andcemented.

Figure 9 is a schematic representation of a well design. For eachhole section, it specifies the diameter of the hole to be drilled, thecasing diameter, weight and grade of steel, and the interval of eachsection to be covered with cement. Note that the hole and casingdiameters decrease for each succeeding section. This is becausethe bit used for each section must be small enough to pass throughthe casing in the section above it. (As drilling technology advances,however, you will probably hear more and more about suchdevelopments as expandable casing, which is being used in some

wells to provide larger hole diameters and thus allow for larger-diameter subsurface equipment to be used where needed.)


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Figure 9:Cross-sectional schematic representation of a well in Brazoria County, Texas summarizinginformation for three main hole sections: 14 3/4 inch, 9 7/8 inch and 6 3/4 inch.

Well Trajectory

A well's trajectorythe path that it follows from the surfacelocation to the targetis one of its most important designcharacteristics. Trajectory planning is based on determining themost economical well course, based on the following parameters:

The depth and coordinates of the subsurface target.

The depth and coordinates of the surface location (as

we shall see below, it is not always directly above thetarget).

The target radius, or how far its final coordinates attarget depth are allowed to deviate from its originallyproposed coordinates (e.g., Is it necessary to drill towithin 100 feet of the specified target coordinates, or isit adequate to come to within 1000 feet?). In general,the smaller the target radius, the more expensive thewell will be to drill).


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The dogleg severity, or maximum change in anglethat is allowed per interval of hole drilled (e.g., adrilling program might restrict a well's dogleg severityto 2 degrees per 100 feet").

With these parameters as a starting point, the two aspects that we

need to consider are deviation control and controlled directionaldrilling.

Deviation control

There's no such thing as a straight hole-- Anonymous

All wells, either by accident or by design, tend to deviate from theirplanned courses. This is a natural consequence of the rotary drillingprocess and the characteristics of drilled formations. Years ago, thisphenomenon was generally beyond the driller's control. Figure 10

shows the results of an older California field.


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Figure 10:

Map view of 14 supposedly "vertical" wells drilled to depths of around 6000 ft. These were laterfound to have drifted hundreds of feet from their surface locations. The surface locations areindicated by a box. (After Suman, 1940. Courtesy Society of Petroleum Engineers).

Although this particular case is extreme, it illustrates the potentialproblems that could result from being unable to control the path ofthe drill bitif, for example, a well was drilled onto someone else'sproperty or even collided with another well (both of these situationshave occurred more than once).

If nothing else, abrupt changes in hole angle increase the bendingstress on drill pipe, often causing it to break apart during drilling.

Rather than live with this situation, companies began developingways to keep wells on course. The resulting advances in drill stringdesign, developments of new subsurface tools and improvements inoperating practices went a long way toward solving these problems.


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Directional Drilling

From controlling wellbore deviation in vertical wells, it was a naturalstep to begin actually guiding drill bits to specific targets: a practiceknown as directional drilling .

Directional drilling has become a critical tool in the oil and gas

industry, particularly in onshore and offshore areas where it isessential to be able to drill multiple wells from a single surfaceinstallation (Figure 11).

Figure 11:Offshore development is an important application of directional drilling. In this case, a vertical welland two directional wells (in blue) were drilled from a single floating platform, along with amultilateralwell (in red on the right), where two extended-reach boreholes branch off from themain wellbore. (Note that the red multilateral well on the left was drilled from a different rig situateddirectly above it, and then tied-back to the platform by a flow-line on the sea floor.)

Horizontal Drilling

Horizontal drilling, a special application of directional drilling,

involves directing part of a well's trajectory through a reservoir suchthat its inclination angle is approximately 90 from vertical (Figure12). The horizontal section may be anywhere from a few feet to

thousands of feet in length.


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Figure 12:

This horizontal well initially follows a vertical trajectory, and begins to build angle at the kick-off point, or KOP (Courtesy Horizontal Solutions International, 1998)

In certain types of reservoirs, horizontal wells are a proven, cost-effective means of increasing exposure to the formation and takingadvantage of its geological characteristics to increase wellproduction, often by three-to-five-fold. Figure 13 shows how a singlehorizontal well can expose as much of a formation as a number ofvertical wells.


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Figure 13:

Using a horizontal well to maximize reservoir exposure and increase production rate 3-5 times.

Geosteering

As companies began drilling longer horizontal and extended-reachwells (e.g., wells drilled from shore to offshore reservoirs up to fivemiles away), it became clear that even the most carefully planneddirectional well might end up missing its target. This is because thetarget formations for such wells are often small and rather uncertainwith respect to their location. Even if the difference is only a matterof a few feet, the result might be an unsuccessful well.

Appropriate technology was soon developed in the form ofMeasurement While Drilling (MWD) and L** While Drilling (LWD)tools located near the drill bit. Integrated MWD and LWD allow forthe geologicallysteering wells as they approach their respective payzonesof using real-time formation measurements to stay withintarget intervals. In a growing number of instances, operators havebeen able to geologically steer wells away from reservoir boundariesand execute successful well completions (Figure 14).


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Figure 14:

Geosteering assembly. Measurements of formation properties, made just above the drill bit, aretransmitted to the surface in real time, where they can be analyzed to make sure that the bit is notstraying out of the desired formation. The orientation of the bit can be modified from the surface toensure an optimal well trajectory, even if that trajectory is different from the one originally planned.

Multilateral Wells

It was another natural step to go from highly deviated and horizontalwells to far more complex, multilateralwell architecture. Some of themore common multilateral well configurations include drilling several

directional or horizontal boreholes from the same vertical well(Figure 15) or, conversely, drilling horizontal or vertical branchesfrom a single horizontal well. In certain types of reservoirs, this canbe an economical alternative to drilling from multiple surfacelocations.


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Figure 15:

Multiple boreholes drilled from a single vertical well are just one application of multilateral drillingtechniques.

Drilling Operations

Rig Systems and Equipment

Figure 16 illustrates the major components of a rotary drilling rig,which we can group into five major systems: hoisting, rotating,circulating, well control and power.


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Figure 16:

Components of a rotary drilling rig (State of California, 2005).

Hoisting and Rotating Systems

The most recognizable parts of a drilling rig are the derrick (ormast) and the substructure upon which it sits. The derrick supports

the weight of the pipe that makes up the drill string and allows it tobe moved up and down. The substructure supports the derrick andprovides workspace for the rig floor equipment.

When it is necessary to remove pipe from the wellto replace a dulldrill bit, for instancethe pipe is lifted out of the hole in sections andstacked to one side of the derrick. The length of pipe that can bedisconnected depends on the height of the mast. A single joint ofdrill pipe is about 30 feet long; the height of a mast that will allow the


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pulling and stacking of pipe, in three-joint sections orstands (90feet), is around 140 feet.

Figure 17 illustrates the main components of the hoisting androtating systems.

The process of lowering pipe into or removing it from the well is

known as tripping. When a drilling crew removes the pipe from awell to replace a bit, and then lowers the pipe with the new bit backto the bottom of the well, this is known as making a round trip.

Hoisting System

To move pipe up or down, the driller spools or unspools a heavysteel cable, ordrilling line, which is wrapped around a large winchcalled a drawworks. This drilling line is threaded through the crownblock (a set of pulleys at the top of the derrick) and then through thetraveling block (another set of pulleys that hangs suspended fromthe crown block). The traveling block moves up as the drilling line isspooled, and down as it is unspoiled; it is connected to a hook thatholds the equipment needed to latch on to the pipe.


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Figure 17:Drilling rig hoisting and rotating systems.

Rotating System

To rotate the drill bit from the surface, the drilling rig's power sourceis used to turn a rotary table that is set into the working floor of the

rig. The rotary table turns a master bushing, into which is set theKelly. The Kelly transmits the rotational movement of the rotarytable to the drill string. The swivel supports the weight of the drillstring, allows it to rotate and provides a pressure-tight connection forpumping drilling fluid down the drill string.

Top-drive unit and power swivel assembly is used as an alternativeto this arrangement on many modern rigs period. In this caserotational energy is transmitted directly from the rig's power sourceto the drill pipe (Figure 18). With a top-drive/power swivel assembly,the driller can drill a complete stand of drill pipe (i.e., 3 or 4 joints ofpipe, or approximately 90-120 feet) before having to stop and makea connection, as opposed to a Kelly/rotary table, where a connectionhas to be made after every joint of pipe (i.e., every 30 feet). Thissignificantly improves the efficiency and safety of drilling operations,and greatly reduces the likelihood of problems normally associatedwith connecting individual segments of the drill string.

Figure 18:Top-drive assembly with power swivel.


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Circulating System

The circulating system continually pumps drilling fluid, (known asmudbecause of its brown color) down the drill string, through the bitand back up to surface. There, drilled rock particles are separatedfrom the mud (Figure 19). The mud is then conditioned and cleaned

before being circulated again

Figure 19:The drilling fluid circulating system. The drilled particles are separated at the shale shaker; othersolids are removed and the mud is re-circulated down the drill pipe.

The mud is one of the most important components of a rotary drillingoperation. In addition to removing rock cuttings from the bottom ofthe well, and cooling and lubricating the bit and drill string, theweight of the mud in the wellbore counteracts and controlssubsurface formation pressure, and prevents fluid invasion fromdrilled formations and hole cave-ins. The effectiveness with which itcarries out these and other functions depends on the componentsand design of the mud system.

Drilling mud is typically a mixture of water, clays, suspended solids,

and chemical additives, although in many areas, an oil-based orsynthetic oil-based fluid might be used; in a few cases, air or foammay serve as a drilling fluid.

The choice of drilling fluid for a particular well is based on suchfactors as the characteristics and composition of the drilledformations, formation temperatures and pressures, anticipateddrilling problems, and the source and quality of the materials used tobuild the mud system.


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Well Control SystemOne thing that we do notwant to happen during drilling operations isto have an uncontrolled influx of formation fluid into the wellbore.This is known as a kick, and it occurs when the pore pressure in apermeable formation exceeds the pressure exerted by the drillingmud in the wellbore (Figure 20).

Example:

We are about to drill into a formation at a depth of 5000 feet. We know from offset well data that the

pore pressure in the formation at this depth is 2250 psi. The well is full of drilling mud having a

density of 9.4 pounds per gallon, which corresponds to a pressure gradient of 0.489 psi/foot.

Is this well about to take a kick?

Answer: The wellbore pressure at the current depth is0.489 psi/ft x 5000 ft = 2445 psi

which is 195 psi greater than the pore pressure. This well is notin immediate danger of taking a

kick.

Figure 20:A kick, or entry of formation fluid into the wellbore, occurs when the pressure exerted by theformation fluid (Ppore) exceeds the pressure exerted by the drilling mud (Pwellbore).
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If a kick is left uncontrolled, the volume of the mud system willincrease as more formation fluid enters the wellbore. The invadingfluid will travel up the wellbore, pushing mud out of the well as itgoes and transmitting the formation pressure to the surface. If thekick reaches the surface in this uncontrolled state (or, in offshoreoperations, the sea floor), then we have the emergency conditionknown as a blowout and if the invading fluid is a hydrocarbon whichignites, we have a major fire (Figure 21). Even if a kick does notreach the surface, it may find its way into a shallow, low-pressureformation, resulting in an underground blowoutalthough this maypresent less of an immediate danger than a surface or sea floorblowout, it is nonetheless a very serious situation.

Figure 21:Fire resulting from a blowout, or uncontrolled release of fluid from a well. While blowouts do notnecessarily result in fires, ignition of the formation fluid is an ever-present concern.

In most drilling operations, the primary means of preventing a kick is

to:

Always keep the well filled with drilling fluid; and

Make sure that the fluid density ormud weightcreates wellbore pressure that is greater than the porepressure.


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If these two conditions are maintained, then the pressure of thedrilling mud pushing down on the formation will exceed the pressureof the formation fluids trying to push into the wellbore.

However, every primary system needs a backup. It is, after all,possible that the level of mud in the well could drop below a certaindepth, or we could encounter higher-than-expected formation

pressures. This is why every drilling rig is designed with a wellcontrol system consisting ofblowout preventers and associatedequipment at the surface.

Blowout preventers (BOPs) are powerful, hydraulically activatedsealing elements that are placed below the drilling rig floor (Figure22). On floating offshore rigs, they are placed on the sea floor.BOPs are designed to close the annular space between the drillstring and the sides of the wellbore, through which mud normallyreturns to the surface. By sealing off this space, the well can beshut-in and the mud and/or formation fluids forced to flow throughan adjustable valve, orchoke and then to a flare or tank. The chokeallows the drilling crew to control the pressure at the surface whilethey kill the wellthat is, while they pump out the formation fluidfrom the well and pump in a higher-density drilling mud to preventfurther influx.

Figure 22:Blowout preventer stack and cross-section. (Courtesy Our Industry Petroleum, BP)

Power Generation and Transmission System

Powerful diesel engines (or, on a few rigs, electric motors) supplyenergy to run the hoisting, rotating and circulating systems. Engine


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capacity may range from 500 to 6000 horsepower, and power maybe transmitted either mechanically or electrically. Modern diesel-electric rigs use their engines to drive generators that produceelectricity. This electricity is sent through cables to a switch andcontrol house, and from there to electric motors that run eachsystem component.

Types of Drilling Rigs

Drilling rigs are broadly categorized as onshore oroffshore, andmay be further classified according to the environments for whichthey are designed (Figure 23).

Figure 23:A land rig and four different types of offshore rigs, each of which is designed for a certain range ofwater depths.

Onshore (Land) Rigs

Onshore rigs are all similar, and many more modern onshore rigsare of the cantilevered mast, or "jackknife" derrick type. This type ofrig allows the derrick to be assembled on the ground, and thenraised to the vertical position using power from the hoisting system(Figure 24). These structures are made up of prefabricated sectionsthat are moved onto the location by truck, barge, helicopter, etc.,and then placed in position and assembled.


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Figure 24:

Raising the derrick on a land rig.

Offshore RigsThere are several types of offshore drilling rigs, each of which issuitable for certain environments and water depths. These rangefrom barge rigs used to drill in shallow inland waters (Figure 25) toself-elevatingjack-up rigs designed for the 30 to 500 foot depthrange (Figure 26) to the self-propelled, floating semisubmersiblerigs (Figure 27) and drill ships (Figure 28) that can drill in watersthousands of feet deep. Offshore rigs can also be mounted on fixeddrilling and production platforms (Figure 29).


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Figure 25:

Barge rig on Lake Erie (http://www.canadian-wellsite.com)
http://www.canadian-wellsite.com/http://www.canadian-wellsite.com/http://www.canadian-wellsite.com/http://www.canadian-wellsite.com/http://www.canadian-wellsite.com/http://www.canadian-wellsite.com/http://www.canadian-wellsite.com/


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Figure 26:

Industries Davie CJ Series Jack Up rig off the coast of Louisiana.


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Figure 27:

PETROBRAS P-36 Semi Submersible Drilling RigEn route to Brazil. (Courtesy Industries Davie)


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Figure 28:Drillship capable of drilling in waters as deep as 10,000 ft.


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Figure 29:Drilling rig on fixed offshore platform off the coast of California (US Department of the Interior,Minerals Management Service).

Subsurface Drilling Equipment

Drill String Components

The longest portion of the drill string consists of connected lengthsofdrill pipe (Figure 30), which provides length to the drill string,

and transmits rotational energy to the drill bit.


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Figure 30:

Drill pipe generally comes in lengths of about 30 feet, which are connected together to form themajor portion of the drill string (courtesy Sub Surface Tools, Inc.).

The bottomhole assembly, orBHA, is that portion of the drill stringbetween the drill pipe and the drill bit. It is made up primarily ofdrillcollars and heavy wall drill pipe, which are thicker and heavierthan regular drill pipe. These add weight to the bit, while keeping thedrill string stable and in tension (Figure 31).


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Figure 31:

Drill collars, the primary component of the Bottomhole Assembly, provide weight to the drill stringand prevent the lighter, more slender drill pipe from buckling.

Stabilizers (Figure 32), are frequently placed at strategic points inthe BHA to keep the drill collars centered, and help to keep the bitheading in the right direction.

Figure 32:A stabilizer, which is used in the bottomhole assembly portion of a dril l string to center the drillcollars in the well and help control the well trajectory. (Courtesy Downhole Stabilization, Inc.)

Other specialized BHA components, arranged in various ways,perform functions ranging from absorbing shock loads and

vibrations, to preventing stuck pipe, to changing the direction of thewell, to collecting real-time drilling and formation data.

Drill Bits

Drill bits (Figure 33) are available from a number of manufacturers.They come in sizes ranging from 3 7/8 to 36 inches in diameter, in abewildering array of types. They can be grouped into two majorcategories: rolling cutter bits and fixed cutter bits.


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Figure 33:

A collection of downhole drilling tools, courtesy of Hughes-Christensen, a division of Baker-HughesIncorporated: (a), (f) and (h) are tungsten-carbide insert bits; (d) is a milled tooth bit; (b), (c), (e) and(k) are polycrystalline diamond compact (PDC) bits; (g) is a impregnated diamond bit; (i) and (j)are hole-opening devices used for reaming or widening hole intervals that have already beendrilled.

Rolling cutter bits have cutting elements arranged on three cones,which rotate on bearings about their own axes as the drill stringturns the body of the bit. The two main types of rolling cutter bits aremilled-tooth bits and tungsten-carbide insert bits.

Fixed cutter bits have stationary cutting elements that are integralwith the body of the bit. The principal types of fixed cutter bits aresteel cutter(fishtail), natural diamond and polycrystallinediamond compact (PDC) bits. It is an 8.5-inch diameter PDC bitthat holds the current footage record for a single bit run: 24,956 feet,at an average penetration rate of 92.5 feet per hour. This record wasset in 2004 in Qatars Idd el Shargi field. (Francis, 2006).

Beyond these general categories, different bit types are used fordifferent formations and drilling conditions. A bit used in soft


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formations (bit d in Figure 33, for example) will be designed toscrape and gouge the rock, much like the digging action of a shovel.A harder formation bit, on the other hand, like bit "a" in Figure 33,will be designed to chip or break up the rock, similar to the action ofa chisel on concrete.

Drilling ProceduresAs each hole section is drilled, the driller carefully monitors andadjusts critical drilling parameters from a control console on the rigfloor (Figure 34). The amount ofweight applied to the bit by the drillstring, for instance, is displayed on a weight indicator and adjustedas necessary by raising or lowering the drill string. Similaradjustments can be made to the rotating speed of the bit, while avariety of other recorders and indicators allow the driller to bequickly informed of any potential problem situations.

Figure 34:

The driller's console on the rig floor.

Drilling Problems

There is a likelihood of problems occurring in any project as involvedas drilling an oil or gas well. While a review of these problems isbeyond the scope of this discussion, suffice it to say that they couldinvolve anything from weather or transportation delays to the drill


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string becoming stuck or breaking off in the well to the potential forkicks or blowouts that we have already addressed.

The best defense against drilling problems is a comprehensive,carefully researched well plan, combined with well-trained rig crews,service company and operating personnel. With these resources inplace, the necessary tools, equipment and procedures can be

readily available and easily implemented should a problem occur.

Remote Monitoring and Operations Support

In years past, if engineers orgeologists wanted to monitor a wellsprogress in real time, they had to be physically present at the drillingrig. Then, if they wanted to consult with other experts from the homeoffice, they had to do so by phone, radio or fax; and by the timeeverybody got together in this manner, the data that they werediscussing might be several hours old.

Today, using high-speed internet or intranet connections, it ispossible to transmit real-time well data directly from the rig to thehome office or other support center, and to present interpretivedisplays of these data (one example now in commercial use isSchlumbergers Operation Support Centers (OSC), based inAberdeen and other strategic locationsseehttp://www.slb.com). Thisimproves the efficiency of the drilling process by enabling as manyexperts as needed to review well progress and recommendimprovements in operating practices, without having to bring themout to the rig, and allowing them to monitor numerous drillingoperations at once from the same location.

Formation Evaluation and TestingAs a well approaches its target depth, preparations begin forevaluating the potentially productive formation. Several methods willhave probably already been in use, such as mud logging. Mudlogging involves the services of a small onsite laboratory andspecialists, who routinely collect, analyze and record drilled cuttingsand gas samples while monitoring drilling mud properties, drillingrates and other parameters (Figure 35). The service is generallyemployed on exploration wells and their major function is to monitorfor the presence of hydrocarbons so as not to miss a potentialproductive formation.
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Figure 35:

Section of a mud log (Courtesy Camco Logging Service).

An inherent shortcoming of mud logging is that it takes timeoftenan hour or morefor the drilling fluid to bring cuttings and formationgas samples to the surface. During that time, the bit may have


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drilled ahead a significant distance, meaning that the data collectedat the surface is obsolete even before it can be analyzed. In someareas, this information gap is not a major concern. In others, it canmean the difference between, say, being prepared to drill into ahigh-pressure formation and encountering it unexpectedly.

One of the most important advances in modern petroleum

technology has been the development of real-time Measurement-While-Drilling (MWD) systems to transmit drilling and directionalinformation, and Logging-While-Drilling (LWD) systems to provideformation evaluation data.

MWD and LWD systems have made it possible to monitor andcontrol operations even as drilling is taking place, by allowingoperators to measure the drill bit position and well trajectory,evaluate drilling parameters, compute pore pressures, and evaluateformations even as they are being drilled. Figure 36 illustrates a

typical MWD-LWD system.

Figure 36:A rotary steering system that incorporates MWD and LWD technology to guide the drill bit andevaluate the formation as it is being drilled. Note how close the various logging sensors (GammaRay, Resistivity, Neutron and Density) are to the drill bit.

If the depth of a formation of interest can be predicted accurately,routine drilling can be stopped just prior to reaching that depth, anda hollow coring bit run to cut a cylindrical sample of rock that can beretrieved at the surface for analysis (Figure 37). Coring is time-consuming and expensive, and is rarely undertaken unless there isa particular need for precise laboratory measurements of rock


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properties. These samples are of special interest to the reservoirengineers who must plan the development of the subsurfacebecause they represent an actual sample of the formation for xxxmeasurement

Figure 37:Coring methods and recovered core material.

Once a hole section is drilled and drill pipe removed, combinationsofopen hole logging devices can be lowered on an electricalconductor cable (Figure 38) to measure and record the properties ofthe rock formations. A gamma ray logging tool, for example, canmeasure a rock's natural radioactivity to determine whether it issand or shale. Resistivity tools, meanwhile, can record the electricalproperties, thus indicating whether it contains oil, gas or salt water(salt water is less resistive to electrical flow than oil and gas). Thesedevices are run on virtually every well that is drilled.


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Figure 38:

Typical onshore well logging setup showing the shale sand shale sequence with the Gamma RayLog (GR) on the left and resistivity log on the right showing the location of the water-oil-gas zones.(Source Industry Petroleum, BP).

Finally, drillstem testing (Figure 39) involves a temporary

completion of a potentially productive zone, allowing the entireformation to produce into the drill pipe for a period of hours tomeasure fluid flow rates and pressures, and then collect fluidsamples. Drillstem tests provide the first indications of how wellsmight produce, and companies usually publish their results aregenerally publicized in the media to announce new discoveries.


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Figure 39:

A Drillstem Test, or DST, involves placing a special tool assembly in the well opposite the formation

of interest, using one or more sealing elements or packers to isolate the zone from the pressure ofthe fluid above it, and temporarily producing the well while measuring the pressure and flow rate inthe formation.

Well CompletionFollowing the well evaluation, the operator has two options toconsider:

Abandonment: Partially or completely plug the wellwith cement according to regulatory standards,possibly recover whatever casing can be removed,and return the surface location to its original condition;and


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Completion: Install the tools and equipment neededto safely produce oil and gas from the well. This optionmay also include stimulatingthe near-well boreformation, either by pumping an acid mixture into theformation or fracturing the rock, to improve the well'sproduction rate.

Completion, the more desirable alternative, will occur for successfulonshore wells, but is not likely for offshore exploratory wells. Theyare usually abandoned after substantial testing ("expendible wells").Development wells are drilled later as an integral part of thedevelopment plan.

Completion Design

The basis for any completion is the steel pipe orcasingthat lines thewellbore. Together with the cement that holds it in place, the casingkeeps the hole from caving in, prevents the flow of fluids and thetransfer of pressures between shallow and deep formations, allowsfor control of pressures; and provides a base of support for surfaceand subsurface equipment.

Figure 40 shows a relatively simple downhole installation consistingofconductorcasing to facilitate the initial drilling of the well,surface casing to protect the shallower rock formations from theharsh conditions encountered at greater depths, and productioncasing designed to isolate the producing formation. In more complexdesigns, one or more intermediate casing strings are placed

between the surface and production casings.


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Figure 40:

Well design showing three strings of casing.

Figure 41 depicts three general options for a well completiondesign.


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Figure 41:

Basic Well Completion Designs: Open hole, slotted liner and case through and perforate.

In an open hole completion (Figure 42(a)), casing is set above or

just into the top of the productive formation, while the bottom of thehole is left uncased. This type of well completion is rarely usedtoday, because it offers little or no control over fluid entry into thewellbore, and increases the potential of hole caving or collapse. Itmay be used in a dry gas well where there is no invasion of water.

In some areas, placing a slotted pipe orscreen across an openhole section can prevent the hole from collapsing (Figure 42(b)).But more often, the movement of sand grains in the formation canlead to serious production problems. To prevent these problems,operators may resort to gravel packing, where the space betweenthe pipe and the open hole is filled with coarse, graded sand toprevent the accumulation of fine solid particles in the wellbore.

By far the most common type of completion today is that in which

casing is cemented through the productive zone (Figure 42(c)). Thisis done by pumping specially designed cement slurry down thecasing, out through a port at the bottom of the casing, and back upto a pre-determined depth in the casing-hole annulus. Once thecasing is cemented and the hole section is sealed off,communication with the formation is re-established by running a toolthat contains explosive charges to selectively perforate holesthrough the casing and cement (Figure 42).


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Figure 42:Perforating Gun showing shaped charges, spaced around the wellbore, which are detonated fromthe surface when in-place.

Using well logs and various depth control techniques, we can selectwhich sections of pay zone to perforate and open to flow, therebyavoiding communication with undesired fluids (gas, water), weakzones that might produce sand, and unproductive sections or shalebarriers. This type of completion is generally used unless there is aspecific reason to prefer an open hole or uncemented linercompletion.

Well Stimulation

Some newly completed wells may not produce at their desired ratesbecause of excessive formation damage. Formation damage occurswhen solids from the drilling mud plug off the rocks pore spaces, or

when the drilling mud reacts with clays in the formation, causingthem to swell and block the pore spaces. Other wells may becompleted in very tight or low-permeability formations that do notallow for high flow rates. In such cases, a stimulation treatmentmaybe included as part of the well program. Depending on the type offormation and the nature of the problem, these treatments mayinvolve procedures known as acidizing, hydraulic fracturing, or acombination of the two. Both of these procedures involve pumpingfluids down into the formation through the tubing or drill pipe.


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In hydraulic fracturing, the objective is to pump fluid ata high enough pressure to actually split the rockformation apart, and then prop the splits open using asuspension of high-permeability sand. This createshigh-permeability flow channels from the formation intothe wellbore.

In acidizing sandstone formations, the objective is topump acid into the existing pore spaces of the rock todissolve clays and other particles that plug the rockspore spaces. Acid treatments in carbonate formationssuch as limestone are different in that the acid actuallydissolves the part of the rock material itself.

Acid-fracturingtreatments are designed to createfractures that are simultaneously widened by aciddissolution.

Production Tubing

The central subsurface component of a completed well is the

production tubing, which is placed inside the casing to serve as aconduit for produced fluids. It is suspended from a tubing hangerwithin the wellhead at the surface (Figure 43) and isolated from theannular space near the bottom of the hole with one or moreproduction packers, which are used to seal off the tubing/casing

annulus or to isolate different producing zones.


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Figure 43:Production tubing suspended from tubing hanger in wellhead and run with a production packer.

There are five primary reasons for using production tubing in a well:(1) It is not cemented into the well, and so it is easy to remove ifproblems develop. (2) It isolates producing fluids from the casingand makes control of the fluids easier. (3) It makes it easier to

circulate fluids (i.e., pump fluids into the well and then back tosurface) for well control or other purposes. (4) Its smaller diameterallows for safety devices and other equipment to be included in thewell design. (5) It enables low-productivity wells to produce fluidmore efficiently.

Some wells may be equipped with multiple packers on a singlestring of tubing, as shown in Figure 44. Here, the well has twoproducing formations, which are isolated by two production packers.The upper producing zone is located between the packers, while thelower producing zone is located below the bottom packer. Acirculating sleeve, or port, which is located between the packers,can be opened to allow fluid from the upper zone to flow into thetubing, or closed to shut off flow from the upper zone. Similarly, a

plug can be placed in the landing nipple below the upper packer toshut off production from the lower zone. When the circulating sleeveis open and there is no plug in the tubing, both the lower and upperzones produce through the same tubing string. Figure 45 showsanother type of dual zone completion, in which multiple packers arerun with dual strings of tubing. Other wells, if they are extremelyproductive, may produce through casing without tubing, or throughboth tubing and the casing-tubing annulus.


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Figure 44:

Well completed with a single string of production tubing and two packers. The well has twoproducing formations, which are isolated by the production packers.


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Figure 45:

Well completed with a dual string of production tubing and two packers. The upper and lower zonescan produce independently through their respective tubing strings.

Wellhead and Surface Flow ControlEquipment

The valves and connections at the top of the well are often referredto collectively as the Wellhead orChristmas tree. This equipmentis designed to safely control the flow of fluids under pressure, sealthe annular openings between concentric casing and tubing strings,monitor annulus and tubing pressures, and provide a base forblowout control equipment during drilling operations.

Figure 46 shows a typical surface flow control installation for aflowing oil well with multiple casing strings and a single tubing string.The flow rate of the well is controlled by the diameter of the

adjustable production choke that is placed at the surface along thetubing flow path.


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Figure 46:

Christmas Tree assembly for a flowing well with several strings of casing and tubing string in thecenter.

Summary

The goals of any drilling venture are to drill safely, provide afit-for-purpose well and minimize the overall well cost.

Companies may have different ideas of how best to attainthese goals, and drilling practices may vary according to

location, rig type, hole conditions or other factors. But the

goals themselves are always the same.

The starting point in meeting drilling objectives is a

comprehensive, thoroughly researched well plan developed by

an integrated team of operating company, drilling contractorand service company personnel. Every aspect of the plan, from

pre-spud activities to completion (or abandonment)

procedures, should be designed to optimize the process of well

construction, and to anticipate and control any problems that


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could arise. The same preparation and effort that goes into

well planning should carry over into well design and day-to-

day operations. Personnel should continually identify, monitor

and evaluate the variables that affect the success of the well,and work to control those variables to their advantage.

Case Study: Nicola Exploration WellYour exploration well team, consisting of your geologist, geophysicist, drilling engineer and

project analyst, has been analyzing the exploration prospect in some detail (see Figure CS1

below). They realize that the Nicola sandstone is in the form of a large structural anticline that

may be quite thick. If oil is discovered the resources within the structure could be huge. Now it is

time to drill a well!

Because the prospect is located on land, they recommend that any promising discovery be

completed as a producing well. The total drilling depth, through the Nicola sandstone, is

estimated to be about feet (meters) in depth.

The team's well plan is shown in Figure CS2. They have also recommended that a mud logging

unit be contracted to be on site during the drilling to make sure we do not miss important shows

of hydrocarbons. They have also recommended that a standard suite of well logs and a Drill

Stem Test (DST) be performed on promising hydrocarbon zones. A fluid sample should be

collected during the DST to record the quality of the crude.

If the well is to be completed, the casing should be cemented through the formation and then

perforated at the top of the sand. Tubing should be hung from the wellhead and separated at the

bottom of the hole with a packer. The proposed completed well arrangement is shown in Figure

CS3.

References

Baker-Hughes (1991):Eastman-Christensen Product Catalog.

Houston: Baker-Hughes, Inc.

Bill Popp, Oil & Gas Liasison, Kenai Peninsala Borough, 43335Kalifornsky Beach Road, #16, Soldotna, AK 99669.

[email protected]

Camco (2005): Corporate website athttp://www.camcologging.com/mudlog.html . LaMarque , TX : CamcoLogging Service.

Horizontal Solutions International (1998). Corporate website athttp://www.horizontalsi.com . Carrollton , TX : Horizontal SolutionsInternational

Levorsen, A.I. (1967).Geology of Petroleum , 2nd ed. SanFrancisco : W.H. Freeman and Co.

Rowe, Morris E. and Wilson, Gerald E. (1981). "How to Get theMost Out of Your Drillstring." Petroleum Engineer International(September).

Smith Bits (2005). Smith Bits Product Catalog. Houston : SmithInternational
mailto:[email protected]:[email protected]://www.camcologging.com/mudlog.htmlhttp://www.camcologging.com/mudlog.htmlhttp://www.horizontalsi.com/http://www.horizontalsi.com/http://www.horizontalsi.com/http://www.camcologging.com/mudlog.htmlmailto:[email protected]


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State of California (2005). Website for Department ofConservation, Division of Oil, Gas & Geothermal

Suman, J.R. (1940): "Drilling, Testing and Completion." Elements ofthe Petroleum Industry , AIME. Richardson , TX : Society ofPetroleum Engineers.

Additional Resources

General Interest:

Baker-Hughes International Rig Count:http://www.bakerhughes.com/investor/rig/

The Baker-Hughes Rig Count is widely used for tracking rig activityin North America and worldwide. Data are available on a weekly andmonthly basis dating back to 1949 for North American rigs, and to1975 for International rigs.

International Association of Drilling Contractors (IADC):http://iadc.org/

The IADC is a professional society whose worldwide membershiprepresents not only drilling contractors, but operating, service andmanufacturing companies as well. Its goal is to promote education,communications and safe, efficient operations within the upstreamoil and gas industry through its training seminars, conferences andwide range of technical publications.

Society of Petroleum Engineers (SPE):http://www.spe.org/

The SPE website contains a number of useful links that can beaccessed by non-members, most of which can be found by going tothe above link and then clicking on the heading titled? About Oil andNatural Gas?

US Department of the Interior, Minerals Management Service(MMS): (http://www.mms.gov/mmshome.htm)

The MMS is the US Government agency charged with overseeingoil and gas operations in federal waters off Alaska, California andthe US Gulf Coast. This site is a good resource for researchingenvironmental and other issues that affect drilling activities.

Drilling Contractors:

The contractors listed below represent some of the major players inthe onshore and offshore drilling industry, and their websites provideboth technical and financial insights. This list is by no means all-inclusive, and it is not meant to reflect an endorsement of anyparticular contractor.

Diamond Offshore Drilling, Inc.:(http://www.diamondoffshore.com)
http://www.bakerhughes.com/investor/rig/http://iadc.org/http://iadc.org/http://www.spe.org/http://www.spe.org/http://www.mms.gov/mmshome.htmhttp://www.mms.gov/mmshome.htmhttp://www.mms.gov/mmshome.htmhttp://www.diamondoffshore.com/http://www.diamondoffshore.com/http://www.diamondoffshore.com/http://www.diamondoffshore.com/http://www.mms.gov/mmshome.htmhttp://www.spe.org/http://iadc.org/http://www.bakerhughes.com/investor/rig/


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Ensco International Incorporated: (http://www.enscous.com)

KCA Deutag: (http://www.kcadeutag.com)

Nabors Industries, Ltd.: (http://www.nabors.com)

Precision Drilling Corporation: (http://www.precisiondrilling.com)

Pride International Inc.: (http://www.prideinternational.com)

Transocean Inc. : (http://www.deepwater.com)
http://www.enscous.com/http://www.enscous.com/http://www.enscous.com/http://www.kcadeutag.com/http://www.kcadeutag.com/http://www.kcadeutag.com/http://www.nabors.com/http://www.nabors.com/http://www.nabors.com/http://www.precisiondrilling.com/http://www.precisiondrilling.com/http://www.precisiondrilling.com/http://www.prideinternational.com/http://www.prideinternational.com/http://www.prideinternational.com/http://www.deepwater.com/http://www.deepwater.com/http://www.deepwater.com/http://www.deepwater.com/http://www.prideinternational.com/http://www.precisiondrilling.com/http://www.nabors.com/http://www.kcadeutag.com/http://www.enscous.com/

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