Basics of Drilling an Oil and Gas Well

Exploration, Development and Abandonment: Before drilling an exploration well an oil company will have to obtain a production licence. Prior to applying for a production licence however the exploration geologists will conduct a ‘scouting’ exercise in which they will analyse any seismic data they have acquired, analyse the regional geology of the area and finally take into account any available information on nearby producing fields or well tests performed in the vicinity of the prospect they are considering. The explorationists in the company will also consider the exploration and development costs, the oil price and tax regimes in order to establish whether, if a discovery were made, it would be worth developing. If the prospect is considered worth exploring further the company will try to acquire a production licence and continue exploring the field. This licence will allow the company to drill exploration wells in the area of interest. It will in fact commit the company to drill one or more wells in the area. The licence may be acquired by an oil company directly from the government, during the licence rounds are announced, or at any other time by farming-into an existing licence. A farm-in involves the company taking over all or part of a licence either: by paying a sum of money to the licencee; by drilling the committed wells on behalf of the licencee, at its own expense; or by acquiring the company who owns the licence. Before the exploration wells are drilled the licencee may shoot extra seismic lines, in a closer grid pattern than it had done previously. This will provide more detailed information about the prospect and will assist in the definition of an optimum drilling target. Despite improvements in seismic techniques the only way of confirming the presence of hydrocarbons is to drill an exploration well. Drilling is very expensive, and if hydrocarbons are not found there is no return on the investment, although valuable geological information may be obtained. With only limited information available a large risk is involved. Having decided to go ahead and drill an exploration well proposal is prepared. The objectives of this well will be:

• To determine the presence of hydrocarbons • To provide geological data (cores, logs) for evaluation • To flow test the well to determine its production potential, and obtain fluid samples.

The life of an oil or gas field can be sub-divided into the following phases: • Exploration • Appraisal • Development • Maintenance • Abandonment

Role of drilling in field development: The length of the exploration phase will depend on the success or otherwise of the exploration wells. There may be a single exploration well or many exploration wells drilled on a prospect. If an economically attractive discovery is made on the prospect then the company enters the Appraisal phase of the life of the field. During this phase more seismic lines may be shot and more wells will be drilled to establish the lateral and vertical extent of (to delineate) the reservoir. These appraisal wells will yield further information, on the basis of which future plans will be based. The information provided by the appraisal wells will be combined with all of the previously collected data and engineers will investigate the most cost effective manner in which to develop the field. If the prospect is deemed to be economically attractive a Field Development Plan will be submitted for approval to the Secretary of State for Energy. It must be noted that the oil company is only a licencee and that the oilfield is the property of the state. The state must therefore approve any plans for development of the field. If approval for the development is received then the company will commence drilling Development wells and constructing the production facilities according to the Development Plan. Once the field is ‘on-stream’ the companies’ commitment continues in the form of maintenance of both the wells and all of the production facilities. After many years of production it may be found that the field is yielding more or possibly less hydrocarbons than initially anticipated at the Development Planning stage and the company may undertake further appraisal and subsequent drilling in the field. At some point in the life of the field the costs of production will exceed the revenue from the field and the field will be abandoned . All of the wells will be plugged and the surface facilities will have to be removed in a safe and environmentally acceptable fashion.

DRILLING PERSONNEL: Drilling a well requires many different skills and involves many companies. The oil company who manages the drilling and/or production operations is known as the operator . In joint ventures one company acts as operator on behalf of the other partners. There are many different management strategies for drilling a well but in virtually all cases the oil company will employ a drilling contractor to actually drill the well.

The drilling contractor owns and maintains the drilling rig and employs and trains the personnel required to operate the rig. During the course of drilling the well certain specialised skills or equipment may be required (e.g. logging, surveying). These are provided by service companies . These service companies develop and maintain specialist tools and staff and hire them out to the operator, generally on a day-rate basis. The contracting strategies for drilling a well or wells range from day-rate contracts to turnkey contracts . The most common type of drilling contract is a day-rate contract . In the case of the day-rate contract the operator prepares a detailed well design and program of work for the drilling operation and the drilling contractor simply provides the drilling rig and personnel to drill the well. The contractor is paid a fixed sum of money for every day that he spends drilling the well. All consumable items (e.g. drilling bits, cement), transport and support services are provided by the operator.

In the case of the turnkey contract the drilling contractor designs the well, contracts the transport and support services and purchases all of the consumables, and charges the oil company a fixed sum of money for whole operation. The role of the operator in the case of a turnkey contract is to specify the drilling targets, the evaluation procedures and to establish the quality controls on the final well. In all cases the drilling contractor is responsible for maintaining the rig and the associated equipment.

The operator will generally have a representative on the rig (sometimes called the “company man” ) to ensure drilling operations go ahead as planned, make decisions affecting progress of the well, and organise supplies of equipment. He will be in daily contact with his drilling superintendent who will be based in the head office of the operator. There may also be an oil company drilling engineer and/or a geologist on the rig.

The drilling contractor will employ a toolpusher to be in overall charge of the rig. He is responsible for all rig floor activities and liaises with the company man to ensure progress is satisfactory. The manual activities associated with drilling the well are conducted by the drilling crew. Since drilling continues 24 hours a day, there are usually 2 drilling crews. Each crew works under the direction of the driller . The crew will generally consist of a derrick man (who also tends the pumps while drilling), 3 roughnecks (working on rig floor), plus a mechanic, an electrician, a crane operator and roustabouts (general labourers). Service company personnel are transported to the rig as and when required. Sometimes they are on the rig for the entire well (e.g. mud engineer) or only for a few days during particular operations (e.g. directional drilling engineer).

THE DRILLING PROPOSAL AND DRILLING PROGRAM: The proposal for drilling the well is prepared by the geologists and reservoir engineers in the operating company and provides the information upon which the well will be designed and the drilling program will be prepared. The proposal contains the following information:

• Objective of the Well • Depth (m/ft Subsea), and Location (Longitude and Latitude) of Target • Geological Cross section • Pore Pressure Profile Prediction

The drilling program is prepared by the Drilling Engineer and contains the following:

• Drilling Rig to be used for the well • Proposed Location for the Drilling Rig • Hole Sizes and Depths • Casing Sizes and Depths • Drilling Fluid Specification • Directional Drilling Information • Well Control Equipment and Procedures • Bits and Hydraulics Program

ROTARY DRILLING EQUIPMENT: The first planned oilwell was drilled in 1859 by Colonel Drake at Titusville, Pennsylvania USA. This well was less than 100 ft deep and produced about 50 bbls/day. The cable-tool drilling method was used to drill this first well. The term cable-tool drilling is used to describe the technique in which a chisel is suspended from the end of a wire cable and is made to impact repeatedly on the bottom of the hole, chipping away at the formation. When the rock at the bottom of the hole has been disintegrated, water is poured down the hole and a long cylindrical bucket (bailer) is run down the hole to collect the chips of rock. Cable-tool drilling was used up until the 1930s to reach depths of 7500 ft.

In the 1890s the first rotary drilling rigs were introduced. Rotary drilling rigs essentially rotary drilling is the technique whereby the rock cutting tool is suspended on the end of hollow pipe, so that fluid can be continuously circulated across the face of the drillbit cleaning the drilling material from the face of the bit and carrying it to surface. This is a much more efficient process than the cable-tool technique. The cutting tool used in this type of drilling is not a chisel but a relatively complex tool ( drillbit ) which drills through the rock under the combined effect of axial load and rotation. The first major success for rotary drilling was at Spindletop, Texas in 1901 where oil was discovered at 1020 ft and produced about 100,000 bbl/day.

THE DRILLING PROCESS: The operations involved in drilling a well can be best illustrated by considering the sequence of events involved in drilling the well shown in Figure below. The dimensions (depths and diameters) used in this example are typical of those found in the North Sea but could be different in other parts of the world.

The following description is only an overview of the process of drilling a well ( the construction process ).

Well Scematic

Well Scematic

Installing the 30” Conductor: The first stage in the operation is to drive a large diameter pipe to a depth of approximately 100ft below ground level using a truck mounted pile-driver. This pipe (usually called casing or, in the case of the first pipe installed, the conductor) is installed to prevent the unconsolidated surface formations from collapsing whilst drilling deeper. Once this conductor, which typically has an outside diameter ( O. D. ) of 30” is in place the full sized drilling rig is brought onto the site and set up over the conductor, and preparations are made for the next stage of the operation.

Drilling and Casing the 26” Hole: The first hole section is drilled with a drillbit, which has a smaller diameter than the inner diameter ( I.D. ) of the conductor. Since the I.D. of the conductor is approximately 28”, a 26” diameter bit is generally used for this hole section. This 26″ hole will be drilled down through the unconsolidated formations, near surface, to approximately 2000′. If possible, the entire well, from surface to the reservoir would be drilled in one hole section. However, this is generally not possible because of geological and formation pressure problems which are encountered whilst drilling. The well is therefore drilled in sections, with casing being used to isolate the problem formations once they have been penetrated. This means however that the wellbore diameter gets smaller and smaller as the well goes deeper and deeper. The drilling engineer must assess the risk of encountering these problems, on the basis of the geological and formation pressure information provided by the geologists and reservoir engineers, and drilling experience in the area. The well will then be designed such that the dimensions of the borehole that penetrates the reservoir, and the casing that is set across the reservoir, will allow the well to be produced in the most efficient manner possible. In the case of an exploration well the final borehole diameter must be large enough to allow the reservoir to be fully evaluated.

Whilst drilling the 26” hole, drilling fluid ( mud ) is circulated down the drillpipe, across the face of the drillbit, and up the annulus between the drillpipe and the borehole, carrying the drilled cuttings from the face of the bit to surface. At surface the cuttings are removed from the mud before it is circulated back down the drillpipe, to collect more cuttings.

When the drillbit reaches approximately 2000’ the drillstring is pulled out of the hole and another string of pipe ( surface casing ) is run into the hole. This casing, which is generally 20″ O.D., is delivered to the rig in 40ft lengths (joints) with threaded connections at either end of each joint. The casing is lowered into the hole, joint by joint, until it reaches the bottom of the hole. Cement slurry is then pumped into the annular space between the casing and the borehole. This cement sheath acts as a seal between the casing and the borehole, preventing cavings from falling down through the annular space between the casing and hole, into the subsequent hole and/or fluids fl owing from the next hole section up into this annular space.

Drilling and Casing the 17 1/2” Hole: Once the cement has set hard, a large spool called a wellhead housing is attached to the top of the 20” casing. This wellhead housing is used to support the weight of subsequent casing strings and the annular valves known as the Blowout prevention (BOP) stack which must be placed on top of the casing before the next hole section is drilled. Since it is possible that formations containing fluids under high pressure will be encountered whilst drilling the next (17 1/2”) hole section a set of valves, known as a Blowout prevention (BOP) stack, is generally fitted to the wellhead before the 17 1/2” hole section is started. If high pressure fluids are encountered they will displace the drilling mud and, if the BOP stack were not in place, would flow in an uncontrolled manner to surface. This uncontrolled flow of hydrocarbons is termed a Blowout and hence the title Blowout Preventers (BOP’s) . The BOP valves are designed to close around the drillpipe, sealing off the annular space between the drillpipe and the casing. These BOPS have a large I.D. so that all of the necessary drilling tools can be run in hole. When the BOP’s have been installed and pressure tested, a 17 1/2″ hole is drilled down to 6000 ft. Once this depth has been reached the troublesome formations in the 17 1/2″ hole are isolated behind another string of casing (13 5/8″ intermediate casing). This casing is run into the hole in the same way as the 20” casing and is supported by the 20” wellhead housing whilst it is cemented in place. When the cement has set hard the BOP stack is removed and a wellhead spool is mounted on top of the wellhead housing. The wellhead spool performs the same function as a wellhead housing except that the wellhead spool has a spool connection on its upper and lower end whereas the wellhead housing has a threaded or welded connection on its lower end and a spool connection on its upper end. This wellhead spool supports the weight of the next string of casing and the BOP stack which is required for the next hole section.

Drilling and Casing the 12 1/4” Hole: When the BOP has been re-installed and pressure tested a 12 1/4″ hole is drilled through the oil bearing reservoir. Whilst drilling through this formation oil will be visible on the cuttings being brought to surface by the drilling fluid. If gas is present in the formation it will also be brought to surface by the drilling fluid and detected by gas detectors placed above the mud flowline connected to the top of the BOP stack. If oil or gas is detected the formation will be evaluated more fully. The drillstring is pulled out and tools which can measure for instance: the electrical resistance of the fluids in the rock (indicating the presence of water or hydrocarbons); the bulk density of the rock (indicating the porosity of the rocks); or the natural radioactive emissions from the rock (indicating the presence of non-porous shales or porous sands) are run in hole. These tools are run on conductive cable called electric wireline , so that the measurements can be transmitted and plotted (against depth) almost immediately at surface. These plots are called Petrophysical logs and the tools are therefore called wireline logging tools. In some cases, it may be desireable to retrieve a large cylindrical sample of the rock known as a core . In order to do this the conventional bit must be pulled from the borehole when the conventional drillbit is about to enter the oil-bearing sand. A donut shaped bit is then attached a special large diameter pipe known as a core barrel is run in hole on the drillpipe. This coring assembly allows the core to be cut from the rock and retrieved. Porosity and permeability measurements can be conducted on this core sample in the laboratory. In some cases tools will be run in the hole which will allow the hydrocarbons in the sand to flow to surface in a controlled manner. These tools allow the fluid to flow in much the same way as it would when the well is on production. Since the produced fluid is allowed to flow through the drillstring or, as it is sometimes called, the drilling string, this test is termed a drill-stem test or DST . If all the indications from these tests are good then the oil company will decide to complete the well . If the tests are negative or show only slight indications of oil, the well will be abandoned.

Completing the Well: If the well is to be used for long term production, equipment which will allow the controlled flow of the hydrocarbons must be installed in the well. In most cases the first step in this operation is to run and cement production casing (9 5/8″ O.D.) across the oil producing zone. A string of pipe, known as tubing (4 1/2″ O.D.), through which the hydrocarbons will flow is then run inside this casing string. The production tubing, unlike the production casing, can be pulled from the well if it develops a leak or corrodes. The annulus between the production casing and the production tubing is sealed off by a device known as a packer. This device is run on the bottom of the tubing and is set in place by hydraulic pressure or mechanical manipulation of the tubing string.

When the packer is positioned just above the pay zone its rubber seals are expanded to seal off the annulus between the tubing and the 9 5/8″ casing. The BOP’s are then removed and a set of valves ( Christmas Tree ) is installed on the top of the wellhead. The Xmas tress is used to control the flow of oil once it reaches the surface. To initiate production, the production casing is “ perforated ” by explosive charges run down the tubing on wireline and positioned adjacent to the pay zone. Holes are then shot through the casing and cement into the formation. The hydrocarbons flow into the wellbore and up the tubing to the surface.

2 Comments

  1. Exploration Drilling

    Drilling Techniques: Drilling techniques are the same, whether on land or at sea. Penetration of the subsurface is achieved by a steel, tungsten carbide or diamond bit attached to screw jointed pipes, rotated at the surface. New lengths of drill pipe are screwed on as the bit descends. From time to time the drill pipe has to be withdrawn to replace the bit or to take core samples. To prevent the hole caving in, a steel casing is inserted. The annular space between the casing and the rock is cemented to prevent fluid movement between strata. Pipe and casing diameters diminish as the well deepens.
    Chemical mud is continuously pumped down the inside of the drill pipe and back up the annulus between the pipe and the side of the hole to the surface. This mud serves to lubricate and cool the bit, to flush out rock chips cut by the bit, to line the hole below the casing, and to prevent formation fluids flowing uncontrollably into the borehole and to the surface. Drilling mud and rock chips are continuously inspected for traces of hydrocarbons and core samples are taken occasionally for more detailed analysis.
    After each section of the hole is completed and before it is cased, wireline log tools are used to plot certain electrical properties of the strata in contact with the well and to provide other data of a geological and geophysical nature, although they cannot detect directly the presence of oil and gas. However, the latter can be done with a drill stem test which stimulates the conditions of a completed well. Such tests can be carried out with or without the casing in place provided the casing, if in place, is first perforated by means of a gun lowered into the hole and fired electrically from the surface.
    The first exploration well may reveal the presence of hydrocarbons that could prove to be commercial in due course. Equally, the first well may be ‘dry’ but it will still provide useful information of geological significance to justify further drilling. A number of dry wells may be drilled before exploration of the area in question is abandoned.
    All wells drilled to discover hydrocarbons are called ‘exploration wells’, commonly known as ‘wild cats’. A successful wild cat is a ‘discovery well’, an unsuccessful one a ‘dry hole’. As a broad indication, and depending upon the nature of the terrain, location, etc., an onshore exploration well can cost up to $10 million and an offshore exploration well, particularly if it is in deep water, up to $20 million.

    Appraisal Drilling and Commerciality Considerations: Once oil or gas has been discovered, additional wells must be drilled to establish the limits of the field; these are known as ‘outstep’ or ‘appraisal’ wells. As more appraisal wells are drilled, more data become available to confirm the nature and quality of the reservoir, e.g. its porosity, permeability, fluid saturations, gas or oil water contact, thickness, pressure, the extent to which wells may be in communication with each other, etc. From all these and other data, the geologist is then better able to define, with the possible help of further seismic surveys, whether the discovery is likely to be technically and commercially exploitable.
    In the case of a natural gas discovery rather different considerations apply as to the assessment of its potential commerciality than to an oil discovery which is usually more straightforward to evaluate. For gas, the key questions to be resolved include: are there nearby market opportunities and, if so, what value (price) can the gas be expected to realise? What then is likely to be the cost of bringing the gas from the reservoir to its point of sale? Alternatively, if there is no nearby market, can one be developed and/or are there any export opportunities?
    Such commercial assessments are normally outside the experience and knowledge of the explorer and appropriate marketing experts need to be called in at a relatively early stage to evaluate the nature and scope of the market opportunities for the (gas) discovery in question. This can be a lengthy, time-consuming process. In some instances, the outcome may be that although there are substantial gas reserves which are technically exploitable, there are no immediate economic commercially exploitable market opportunities. In that event, the decision may be taken to stop any further appraisal drilling and to log and cap those wells that have already been drilled, in effect to abandon that particular exploration effort until such time as a market opportunity develops. In extreme cases, if no market opportunity is likely to arise over the foreseeable future, the exploration effort, which was probably directed at discovering oil in the first instance, can be regarded to all intents and purposes as being abortive even though gas, but no oil, was discovered.
    All exploration for hydrocarbons is a high risk activity with the commercial risks usually being greatest for gas, particularly in locations remote from market, for the reasons indicated above. An important consideration in any exploration venture which affects commercial viability if hydrocarbons are discovered, is the fiscal framework and related contractual arrangements within which the company has to operate.

    Fiscal Framework :In virtually all countries mineral rights are vested in the state. Oil and gas industry operations can only be carried out under licences or contracts granted by governments. Important considerations for the exploring company are the investment at risk, i.e. the amount of work required and/or specified by government to explore the area adequately, the ability to manage operations, access to hydrocarbons if exploration is successful, and the economic return.
    Licences are the traditional form of mining agreement where the government grants exclusive rights to a company, or a consortium of companies, to explore in a particular area. The company is responsible for financing the exploration and, if successful, is entitled to dispose of the production sometimes subject to deduction of royalty in kind. Government revenues come from this royalty and taxation.
    An alternative arrangement which is becoming more common is a production sharing contract where the company takes the full exploration risk. It also pays all development and operating costs, which are recovered out of part of the production, referred to as `cost gas (or oil)’. The remaining `profit gas (or oil)’ is then split in a predetermined manner between the company and the government. Royalty may also apply. Risk contracts are where the company finances all exploration, in some cases all production costs as well, and is required to sell all production to the state oil and Gas Company and to take its return in cash or kind.
    Association contracts involve a joint venture between the company and the state company, but otherwise are similar to a license arrangement.
    Basically governments obtain their revenues from a successful venture by various combinations of royalty as a percentage of production, royalty taken in kind, participating in the venture, corporation taxes or through special petroleum taxes. Windfall profits taxes are not uncommon in situations where realized prices for the hydrocarbons rise substantially above previously assumed expectations. Equally, there are examples of governments moderating their fiscal terms when they have been too onerous to attract exploration activity or when prices have fallen to such an extent that the venture is no longer economically viable.
    Of necessity, in a book that endeavors to encompass the whole spectrum of the natural gas business, the foregoing is only a brief, simplistic and incomplete account of some geological aspects and activities involved in exploring for hydrocarbons. Exploration is arguably the most sophisticated and intellectually demanding task undertaken by the oil and gas industry. Knowledge of the earths subsurface and exploration techniques are continually improving but, as stated earlier, exploration is a high risk venture; in the final analysis only expensive drilling can confirm if hydrocarbons are present.
    On a worldwide basis, average annual rates of discovery of new gas reserves over the last decade or so have exceeded annual production rates by a factor of about four. On the one hand, this means those in global terms the life time, or reserves: production ratio is increasing. On the other hand, as the majority of new gas discoveries in recent years have been made in areas remote from markets and thus are not always economic to develop, the need to find new gas reserves in exploitable locations remains a prime task. A further challenge for the gas industry is to find useful ways and means of utilizing gas produced in association with oil in remote locations: it is estimated that the equivalent of more than 2 million barrels per day of associated gas is vented or flared.
    To sum up, the world has a relative abundance of gas resources but many of these are in the `wrong’ place. The focus of gas exploration is to find more gas in the ‘right’ place.

  2. Well Planning: There are many aspects involved in well planning, and many individuals from various companies and disciplines are involved in designing various programs for the well (mud program, casing program, drill string design, bit program, etc). A novel approach to well planning is one where the service contractors become equally involved in their area of expertise. This section will concentrate on those aspects of well planning which have always been the province of directional drilling companies.

    Reference Systems and Coordinates: With the exception of Inertial Navigation Systems, all survey systems measure inclination and azimuth at a particular measured depth (depths measured “along hole”). These measurements are tied to fixed reference systems so that the course of the borehole can be calculated and recorded. These reference systems include:
    • Depth references
    • Inclination references
    • Azimuth references

    Depth References: During the course of a directional well, there are two kinds of depths:
    • Measured Depth (MD) is the distance measured along the actual course of the borehole from the surface reference point to the survey point. This depth is always measured in some way, for example, pipe tally, wireline depth counter, or mud loggers depth counter.
    • True Vertical Depth (TVD) is the vertical distance from the depth reference level to a point on the borehole course. This depth is always calculated from the deviation survey data.

    In most drilling operations the rotary table elevation is used as the working depth reference. The abbreviation BRT (below rotary table) and RKB (rotary kelly bushing) are used to indicate depths measured from the rotary table. This can also be referred to as derrick floor elevation. For floating drilling rigs the rotary table elevation is not fixed and hence a mean rotary table elevation has to be used. In order to compare individual wells within the same field, a common depth reference must be defined and referred to (e.g. When drilling a relief well into a blow-out well, the difference in elevation between the wellheads has to be accurately known). Offshore, mean sea level (MSL) is sometimes used. Variations in actual sea level from MSL can be read from tide tables or can be measured.

    Inclination References: The inclination of a well-bore is the angle (in degrees) between the vertical and the well bore axis at a particular point. The vertical reference is the direction of the local gravity vector and could be indicated by a plumb bob.

    Azimuth Reference Systems: For directional surveying there are three azimuth reference systems:
    • Magnetic North
    • True (Geographic) North
    • Grid North

    All “magnetic-type” tools give an azimuth (hole direction) referenced to Magnetic North. However, the final calculated coordinates are always referenced to either True North or Grid North.

    True (Geographic) North: This is the direction of the geographic North Pole which lies on the Earth’s axis of rotation. Direction is shown on maps using meridians of longitude.

    Grid North: Drilling operations occur on a curved surface (i.e, the surface of the Earth) but when calculating horizontal plane coordinates a flat surface is assumed. Since it is not possible to exactly represent part of the surface of a sphere on a flat well plan, corrections must be applied to the measurements. To do this, different projection systems which can be used.

    UTM System: One example of a grid system is the Universal Transverse Mercator (UTM) System. In transverse mercator projection, the surface of the spheroid chosen to represent the Earth is wrapped in a cylinder which touches the spheroid along a chosen meridian. (A meridian is a circle running around the Earth passing through both North and South geographic poles.) These meridians of longitude converge towards the North Pole and do not produce a rectangular grid system. The grid lines on a map form the rectangular grid system, the Northerly direction of which is determined by one specified meridian of longitude. This “Grid North” direction will only be identical to “True North” on a specified meridian.

    Lambert Projection:
    Another projection system, used in some parts of the world, is the conical projection or LAMBERT system. A cone as opposed to a cylinder covers the spheroid under consideration. This produces a representation with meridians as convergent lines and parallels as arcs of circles.

    Field Coordinates: Although the coordinates of points on a wellpath could be expressed as UTM coordinates, it is not normal practice. Instead, a reference point on the platform or rig is chosen as the local origin and given the coordinates 0,0. On offshore platforms this point is usually the center of the platform.
    The Northings and Eastings points on the wells drilled from the platform are referenced to this single origin. This is important when comparing positions of wells, in particular for anti-collision analysis.

    Direction Measurements: Survey tools measure the direction of the wellbore on the horizontal plane with respect to North reference, whether it is True or Grid North. There are two systems:

    Azimuth: In the azimuth system, directions are expressed as a clockwise angle from 0° to 359.99°, with North being 0°.

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