When there is only one type of fluid flowing through porous media, the permeability for this case is called “absolute permeability.” However, when there is more than one type of fluids present in a rock, a permeability of each fluid to flow is decreased because another fluid will be moving in the rock as well. A new term of permeability called “effective permeability” is a permeability of a rock to a particular fluid when more than one type of fluid is in a rock
Reservoir consists of three fluids (gas, oil, and water) so these are commonly used abbreviations for effective permeability for each fluid.
kg = effective permeability to gas
ko = effective permeability to oil
kw = effective permeability to water
Normally, it is common to state effective permeability as a function of a rock’s absolute permeability. Relative permeability is defined as a ration of effective permeability to an absolute permeability of rock. The relative permeability is widely used in reservoir engineering. These functions below are the relative permeability of gas, oil, and water.
krg = kg ÷ k
kro = ko ÷ k
krw = kw ÷ k
k = absolute permeability
Fig.1Fig.2
Relative permeability is normally plotted as a function of water saturation in a rock . Figure 1 demonstrates a plot of oil-water relative permeability curves.
As water saturation (Sw) decreases, relative permeability of oil (Kro) decreases and relative permeability of water increases (Krw). If water saturation is
below connate water saturation (Swc), only oil will flow, but water will not flow (Figure 2)
When water saturation (Sw) in a rock is equal to connate water saturation (Swc), water starts to flow (Figure 3) Water starts to flow at Swc.
Fig.3
Oil flow continues to decrease and water flow continues to decrease because the water saturation goes up. If water saturation (Sw) is between connate water saturation (Swc) and 1 minus Sor (irreducible oil saturation), both oil and water flow (Figure4).
Once water saturation in a rock increases to 1 minus Sor (irreducible oil saturation), oil will not flow, but only water will flow. Beyond this point oil will not move at all but water will continue to increase as water saturation (Sw) in a rock increases (Figure5).
An effective HSE program is characterized by no injury to people, no loss of property, and no harm to the environment. Great HSE performance is anindication of great leadership. It is much more than statistics, although measurements are necessary to facilitate performance improvement. HSE must be considered a core responsibility for all business participants, operators, contractors, and service companies and be accepted by all individuals on a personal basis. It is imperative that all parties are committed from the top management down throughout their organizations.
The main reasons companies in the current era support strong HSE programs include humanitarian reasons (i.e., not hurting people), legal or regulatory requirements, the company’s public image, employee morale, and economic reasons (i.e., loss of business or the cost of poor HSE performance).
The modern era of HSE management for oil field operations began with the Piper Alpha disaster in the North Sea, where 167 men lost their lives in one incident. The subsequent investigation, conducted and published by Lord Cullen, contained the framework of HSE management embodied in much subsequent legislation and regulation. This was the birth of safety cases for oil field facilities, including offshore MODU drilling rigs.
One of the key recommendations was that companies should have safety management systems (SMSs) that control a company’s operations from top to bottom. The systems were recommended to include the elements of ISO 9001 (a standard for management of quality in organizations) and include elements such as management responsibility and commitment, design control, documentation and procedures, process control, control of non conformance, corrective actions, internal auditing, and training. All the elements of a safety management system are not directly applicable to drilling optimization and are therefore not addressed here.
Examples include emergency response plans and oil spill response procedures that companies should have in place as part of their normal procedures.
Generally, each drilling department should have a set of operating guidelines that control the drilling work processes. The operating guidelines are a subset of the SMSs, and the documents may vary from multivolume sets at the major oil companies to much smaller documents for smaller companies.
The drilling engineer is responsible for ensuring that all his work complies with these guidance instructions. Variations from these procedures usually will require a higher level of management approval.
The three components of HSE-related drilling issues that are normally considered during drilling operations are discussed separately in the following sections.
1.Health
Health issues related to drilling operations can include industrial hygiene issues related to onsite conditions and may include exposures to drilling fluid components such as oil-base mud fumes and skin contact, highly toxic completion brines, or oils, gas, and toxic materials such as hydrogen sulfide originating from the well. Naturally occurring radioactive materials (NORM) can also be encountered during workover operations, and metals such as mercury are encountered periodically in gas
streams and may be found in production separators.An optimized drilling program includes careful consideration of the health impact on employees
and workers at any well site.
2.Safety
The general safety culture adapted in the current era was derived from the Dont manufacturing culture and adapted to oil field operations when the company purchased Conoco. Dont was originally in the dynamite manufacturing business, and serious accidents in the past strongly motivated management to adopt a “best practice” approach to safety management.
The primary concept is that all accidents are preventable. Accidents do not just happen, and with work, resources, and management commitment, accidents can be minimized or eliminated. In most all oil companies and service companies, management personnel leave no doubt that they are committed to providing a safe working environment. A poor safety record leads to the suffering of injured employees, the financial impact of lawsuits, and the loss of business and shareholder support. It is not unusual for service companies to be removed from approved bidding lists if the safety performance is not up to the company’s requirements. The second
concept generally accepted is that safety (or HSE) must be considered equally with production and profits in the decision-making process. “Safety first” is
not plausible. If we wanted to only be safe, we would never leave the comfort of our homes in the first place. Safety must be considered as an equal
to other factors in the decision-making process to ensure that all jobs meet the company’s safety goals.
Safety management is an engineering profession unto itself, with many disciplines and areas of coverage. For the drilling engineer or drilling foreman, safety at the well site is accomplished through sound engineering, formal safety reviews (as appropriate), contracting of reputable firms with strong safety cultures, and appropriate training of all personnel.
Operational risks for drilling operations can vary from simple, shallow onshore jobs to extremely complex offshore operations in remote hostile areas that can be extremely expensive and carry significant risk. Consequently, a “fit for purpose” approach must be considered for the safety management of each operation. Asimple onshore job may rely completely on the drilling contract and include relatively simple tools such as a toolbox safety discussion and daily safety meeting. At the other end of the
scale, in large offshore production platforms with simultaneous operation of wells and drilling in a remote or hostile area, a large amount of safety engineering may be required. Tools may include a full safety case preparation and hazard and operability (HAZOP) studies . A HAZOP study is an examination procedure. Its purpose is to identify all possible deviations from the way in which a design is expected to work and to identify all the hazards associated with these deviations. When deviations
arise that result in hazards, actions are generated that require design engineers to review and suggest solutions to remove the hazard or reduce its risk to an acceptable level. These solutions are reviewed and accepted by the HAZOP team before implementation. HAZOP techniques have been adopted by many countries and are required to provide assurance of safe operations.
It should be understood by all operation personnel that 96% of all accidents are related to unsafe behaviors and that only 4% of accidents are caused by unsafe conditions. Most drilling contractors have adopted policies that focus on encouraging safe behaviors.
3.Environment
Dramatic changes in environmental impact management have occurred continually from the earliest days of the oil field. Common practice in the early days was to produce oil into open pits for storage. Saltwater was routinely dumped into the nearest creek, killing everything in it. Today’s best practices include serious management and minimization of all waste streams. Development of projects today may require full environmental impact assessments (EIA) before approval. The first legal requirement in
the United States for an EIA was imposed on the Trans-Alaska oil pipeline, which was delayed for years and experienced cost overruns from an initial
estimate of $900 million to a final installed cost of $9 billion. Today, most of the East and West coastlines of the United States and Florida are off limits
for drilling because of environmental concerns. The Exxon Valdez incident will not leave the collective public memory any time soon and is an example of the negative impact to the environment from oil and gas operations.
Most companies have management systems in place for environmental management of their operations. Drilling personnel are responsible for planning and conducting operations to ensure optimization and compliance. References: 1. Drilling Equipment and Operation.
2. drilling Operation.
Basically all formations penetrated during drilling are porous and permeable to some degree.
Fluids contained in pore spaces are under pressure that is overbalanced by the drilling fluid pressure in the well bore.
The borehole pressure is equal to the hydrostatic pressure plus the friction pressure loss in the annulus. If for some reason the borehole pressure falls below the formation fluid pressure, the formation fluids can enter the well. Such an event is known as a kick. This name is associated with a rather sudden flowrate increase observed at the surface.
SURFACE EQUIPMENT
A formation gas or fluid kick can be efficiently and safely controlled if the proper equipment is installed at the surface. One of several possible arrangement of pressure control equipment . The blowout preventer (BOP) stack consists of a spherical preventer (i.e.,Hydril) and ram type BOPs with blind rams in one and pipe rams in another with
a drilling spool placed in the stack.
A spherical preventer contains a packing element that seals the space around the outside of the drill pipe. This preventer is not designed to shut off the well when the drill pipe is out of the hole. The spherical preventer allows stripping operations and some limited pipe rotation.
Hydril Corporation, Shaffer, and other manufactures provide several models with differing packing element designs for specific types of service. The ram type preventer uses two concentric halves to close and seal around the pipe, called pipe rams or blind rams, which seal against the opposing half when there is no pipe in the hole. Some pipe rams will only seal on a single size pipe; 5 in. pipe rams only seal around 5 in. drill pipe. There are also variable bore rams, which cover a specific size range such as 312 in. to 5 in. that seal on any size pipe in their range.
Care must be taken before closing the blind rams. If pipe is in the hole and the blind rams are closed, the pipe may be damaged or cut. A special type of blind rams that will sever the pipe are called shear blind rams.
These rams will seal against themselves when there is no pipe in the hole, or, in the case of pipe in the hole, the rams will first shear the pipe and then
continue to close until they seal the well. A drilling spool is the element of the BOP stack to which choke and kill lines are attached. The pressure rating of the drilling spool and its side outlets should be consistent with BOP stack. The kill line allows pumping mud into the annulus of the well in the case that is required. The choke
line side is connected to a manifold to enable circulation of drilling and formation fluids out of the hole in a controlled manner.
A degasser is installed on the mud return line to remove any small amounts of entrained gas in the returning drilling fluids. Samples of gas
are analyzed using the gas chromatograph.
If for some reason the well cannot be shut in, and thus prevents implementation of regular kick killing procedure, a diverter type stack is used rather, the BOP stack described above. The diverter stack is furnished with a blow-down line to allow the well to vent wellbore gas or fluids a safe distance away from the rig.
WHEN AND HOW TO CLOSE THE WELL
While drilling, there are certain warning signals that, if properly analyzed, can lead to early detection of gas or formation fluid entry into the wellbore.
1. Drilling break. A relatively sudden increase in the drilling rate is called a drilling break. The drilling break may occur due to a decrease in the difference between borehole pressure and formation pressure. When a drilling break is observed, the pumps should be stopped and the well watched for flow at the mud line. If the well does not flow, it probably means that the overbalance is not lost or simply that a softer formation has be encountered.
2. Decrease in pump pressure. When less dense formation fluid enters the borehole, the hydrostatic head in the annulus is decreased. Although reduction in pump pressure may be caused by several other factors, drilling personnel should consider a formation fluid influx into the wellbore as one possible cause. The pumps should be stopped and the return flow mud line watched carefully.
3. Increase in pit level. This is a definite signal of formation fluid invasion into the wellbore. The well must be shut in as soon as possible.
4. Gas-cut mud. When drilling through gas-bearing formations, small quantities of gas occur in the cuttings. As these cuttings are circulated up, the annulus, the gas expands. The resulting reduction in mud weight is observed at surface.
Stopping the pumps and observing the mud return line help determine whether the overbalance is lost.
If the kick is gained while tripping, the only warning signal we have is an increase in fluid volume at the surface (pit gain). Once it is determined that the pressure overbalance is lost, the well must be closed as quickly as possible. The sequence of operations in closing a well is as follows:
1. Shut off the mud pumps.
2. Raise the Kelly above the BOP stack.
3. Open the choke line
4. Close the spherical preventer.
5. Close the choke slowly.
6. Record the pit level increase.
7. Record the stabilized pressure on the drill pipe (Stand Pipe) and annulus pressure gauges.
8. Notify the company personnel.
9. Prepare the kill procedure.
If the well kicks while tripping, the sequence of necessary steps can be given below:
Close the safety valve (Kelly cock) on the drill pipe.
2. Pick up and install the Kelly or top drive.
3. Open the safety valve (Kelly cock).
4. Open the choke line.
5. Close the annular (spherical) preventer.
6. Record the pit gain along with the shut in drill pipe pressure (SIDPP) and shut in casing pressure (SICP).
7. Notify the company personnel.
8. Prepare the kill procedure.
Depending on the type of drilling rig and company policy, this sequence of operations may be changed.
A formation fluid influx (a kick) may result from one of the following
reasons:
• abnormally high formation pressure is encountered
• lost circulation mud weight too low
• swabbing in during tripping operations
• not filling up the hole while pulling out the drill string
• recirculating gas or oil cut mud.
If a kick is not controlled properly, a blowout will occur.
A blowout may develop for one or more of the following causes:
• lack of analysis of data obtained from offset wells
• lack or misunderstanding of data during drilling
• malfunction or even lack of adequate well control equipment
References:
1. Drilling Equipment and Operation.
2. drilling Operation.
Petroleum, meaning literally “rock oil,” is the term used to describe a myriad of hydrocarbon-rich fluids that have accumulated in subterranean reservoirs. (also called crude oil) varies dramatically in color, odor, and flow properties that reflect the diversity of its origin.
Petroleum products are any petroleum-based products that can be obtained by refining and comprise refinery gas, ethane, liquefied petroleum gas (LPG), naphtha, gasoline, aviation fuel, marine fuel, kerosene, diesel fuel, distillate fuel oil, residual fuel oil, gas oil, lubricants, white oil, grease, wax, asphalt, as well as coke.
Crude oils are complex mixtures of these hydrocarbons. Oils containing primarily paraffin hydrocarbons are called paraffin-based or paraffinic. Traditional examples are Pennsylvania grade crude oils. Naphthenic-based crudes contain a large percentage of cycloparaffins in the heavy components. Examples of this type of crude come from the United States midcontinent region. Highly aromatic crudes are less common but are still found around the world.
Crude Oil Composition
Crude oils tend to be a mixture of paraffins, naphthenes, aromatics, with paraffins and naphthenes the predominant species. Resins and asphaltenes may also be present in crude oil. Resins and asphaltenes are the colored and black components found in oil and are made up of relatively high-molecular weight, polar, polycyclic, aromatic ring compounds. Pure asphaltenes are nonvolatile, dry, solid, black powders, while resins are heavy liquids or sticky solids with the same volatility as similarly sized hydrocarbons. High-molecular-weight resins tend to be red in color, while lighter resins are less colored. Asphaltenes do not dissolve in crude oil but exist as a colloidal suspension. They are soluble in aromatic compounds such as xylene, but will precipitate in the presence of light paraffinic compounds such as pentane. Resins, on the other hand, are readily soluble in oil.
Petroleum products are highly complex chemicals, and considerable effort is required to characterize their chemical and physical properties with a high degree of precision and accuracy. Indeed, the analysis of petroleum products is necessary to determine the properties that can assist in resolving a process problem as well as the properties that indicate the function and performance of the product in service.
Crude petroleum and the products obtained there from contain a variety of compounds, usually but not always hydrocarbons. As the number of carbon atoms in, for example, the paraffin series increases, the complexity of petroleum mixtures also rapidly increases. Consequently, detailed analysis of the individual constituents of the higher boiling fractions becomes increasingly difficult, if not impossible.
Additionally, classes (or types) of hydrocarbons were, and still are, determined based on the capability to isolate them by separation techniques. The four fractional types into which petroleum is subdivided are paraffins, olefins, naphthenes, and aromatics (PONA). Paraffinic hydrocarbons include both normal and branched alkanes, whereas olefins refer to normal and branched alkenes that contain one or more double or triple carbon-carbon bonds. Naphthene (not to be confused with naphthalene) is a term specific to the petroleum industry that refers to the saturated cyclic hydrocarbons (cycloalkanes). Finally, the term aromatics includes all hydrocarbons containing one or more rings of the benzenoid structure.
Although not directly derived from composition, the terms light and heavy or sweet and sour provide convenient terms for use in descriptions. For example, light petroleum (often referred to as conventional petroleum) is usually rich in low-boiling constituents and waxy molecules whereas heavy petroleum contains greater proportions of higher-boiling, more aromatic, and heteroatom-containing (N-, O-, S-, and metal containing) constituents. Heavy oil is more viscous than conventional petroleum and
requires enhanced methods for recovery. Bitumen is near solid or solid and cannot be recovered by enhanced oil recovery methods.
onventional (light) petroleum is composed of hydrocarbons together with smaller amounts of organic compounds of nitrogen, oxygen, and sulfur and still smaller amounts of compounds containing metallic constituents, particularly vanadium, nickel, iron, and copper. The processes by which petroleum was formed dictate that petroleum composition will vary and be site specific, thus leading to a wide variety of compositional differences.
The term site specific is intended to convey that petroleum composition will be dependent on regional and local variations in the proportion of the various precursors that went into the formation of the protopetroleum as well as variations in temperature and pressure to which the precursors were subjected.
Thus the purely hydrocarbon content may be higher than 90% by weight for paraffinic petroleum and 50% by weight for heavy crude oil and much lower for tar sand bitumen. The nonhydrocarbon constituents are usually concentrated in the higher-boiling portions of the crude oil. The carbon and hydrogen content is approximately constant from crude oil to crude oil even though the amounts of the various hydrocarbon types and of the individual isomers may vary widely. Thus the carbon content of various types of petroleum is usually between 83% and 87% by weight and the hydrogen content is in the range of 11–14% by weight.
General aspects of petroleum quality (as a refinery feedstock) are assessed by measurement of physical properties such as relative density (specific gravity - which affects on Oil Price), refractive index, or viscosity, or by empirical tests such as pour point or oxidation stability that are intended to relate to behavior in service. In some cases the evaluation may include tests in mechanical rigs and engines either in the laboratory or under actual operating conditions.
Measurements of bulk properties are generally easy to perform and, therefore, quick and economical. Several properties may correlate well with certain compositional characteristics and are widely used as a quick and inexpensive means to determine those characteristics. The most important properties of a whole crude oil are its boiling-point distribution, its density (or API gravity), and its viscosity. The boiling-point distribution, boiling profile, or distillation assay gives the yield of the various distillation cuts, and selected properties of the fractions are usually determined.
It is a prime property in its own right that indicates how much gasoline and other transportation fuels can be made from petroleum without conversion.
Density and viscosity are measured for secondary reasons.
The former helps to estimate the paraffinic character of the oil, and the latter permits the assessment of its undesirable residual material that causes resistance to
flow. Boiling-point distribution, density, and viscosity are easily measured and give a quick first evaluation of petroleum oil. Sulfur content, another
crucial and primary property of a crude oil, is also readily determined. Certain composite characterization values, calculated from density and
mid-boiling point, correlate better with molecular composition than density alone.
The acceptance of heavy oil and bitumen as refinery feedstocks has meant that the analytical techniques used for the lighter feedstocks have
had to evolve to produce meaningful data that can be employed to assist in defining refinery scenarios for processing the feedstocks. In addition,
selection of the most appropriate analytical procedures will aid in the predictability of feedstock behavior during refining. This same rationale can also be applied to feedstock behavior during recovery operations. Indeed,bitumen, a source of synthetic crude oil, is so different from petroleum that many of the test methods designed for petroleum may need modification.
References: 1. Petroleum & Gas Field Processing, H K. Abdel-Alal and Mohamed Aggour, King Fahd University of Petroleum & Minerals 2. Petroleum Engineering Handbook, L.W.Lake, Vol.1 “General Engineering”
The major portion of drill string is composed of drill pipe. Drill pipe consists of three components: a tube with a pin tool joint welded to one end and a box tool joint welded to the other. Before the tool joints are welded to the tube, the tube is upset, or forged, on each end to increase the wall thickness. After upsetting, the tube is heat treated to the proper grade strength. All tool joints are heat treated to the same material yield strength (120,000 psi), regardless of the grade of pipe to which they are attached. Most drill pipe is made from material similar to AISI 4125/30 steel seamless tube. Most tool joints are made from material similar to AISI 4140 steel forgings, tubing, or bars stock.
Drilling Pipes
Drilling Pipes
Drill pipe dimensional and metallurgical specifications are defined by the American Petroleum Institute (API) and published in API Spec 7 Specifications for Drill Stem Elements and API Spec 5D Specifications for Drill Pipe. Performance characteristics, guidelines for drill pipe use and inspection standards are in API RP7G Recommended Practice for Drill Stem Design and Operating Limits. Drill pipe specifications and performance characteristics can also be found in ISO 10407-1, ISO 10407-2, ISO 10424-1, ISO 10424-2, and ISO 11961. This list is not all inclusive; it contains drill pipe assemblies with various tool joints but not all OD and ID combinations of tool joints.
The following items are required to completely identify a length of drilling pipe: - Pipe size is the pipe OD (in., mm). The API specification for the drill pipe tube is API 5D. - Pipe weight (lb/ft, kg/m) is for the tube only exclusive of tool joints and upset ends and is used to specify wall thickness. Except in a few cases, the tabulated pipe weight is not the calculated pipe weight.
- Pipe grade is the pipe yield strength. Drill pipe manufacturers may offer higher strength grades or grades designed for specific applications such as drilling in H2S environments. Pipe upset The drill pipe tubes are upset on each end to increase the wall thickness. The thicker wall is needed to compensate for loss of material strength during the welding process. There are three configurations of upsets: • Internal upset (IU), inwhich the wall thickness is increased by decreasing the ID. This allows smaller OD tool joints to be welded to the pipe. This pipe is sometimes referred to as a slim hole pipe and is used in smaller diameter holes. • External upset (EU), inwhich the wall thickness is increased by increasing the OD. This allows larger tool joints to be welded to the pipe. The larger tool joints provide more torsional strength and create a lower pressure drop than those used on IU pipe. • Internal external upset (IEU), in which the wall thickness is increased by increasing the OD and decreasing the ID. This is the most common upset type on pipe larger than 4 in. Tool joint type. The API tool joint types are printed in bold. These include API Reg (used mostly for drill collars, bits, subs and other bottom-hole assembly components), NC numbered connections, and 512 and 658 full hole (FH). Before the NC-type connections were established, tool joint manufacturers often produced interchangeable tool joints with different names. The NC connections were established to reduce the number of tool joint types. Tool joints with the same thread form and pitch diameter at the gage point are usually interchangeable. Drill pipe manufacturers may also offer proprietary tool joints, such as different variations of double shoulder tool joints for increased torsional strength and tool joints with special threads.
Tool joint OD and ID.
The OD and ID (in., mm) of the tool joint dictates its strength. Generally, the torsional strength of the box is dictated by the tool joint OD and that of the pin is dictated by the ID. Because the box strength does not depend on its ID, the box ID of most drill pipe assemblies is the maximum available regardless of the pin ID. The tool joint OD affects the fish ability of the length and the equivalent circulation density (ECD). The tool joint ID affects the drilling fluid pressure losses in the string.
Tool joint tong length.
The tong length (in, mm) is the length of the cylindrical portion of the tool joint where the tongs grip. API specifies tong lengths for API connections. Drill pipe is often produced with tong lengths greater than the API-specified tong length, usually in 1-inch increments, to allow more thread recuts. Each time a damaged thread is recut, about 3- 4 in. of tong space is lost.
Drill pipe length.
API-defined drill pipe is available in three standard lengths: range 1, range 2, and range 3, which are approximately 22, 3112 , and 45 ft long, respectively.
Hardbanding. Drill pipe is often producedwith hardbanding on the box. The hardbanding reduces the wear rate of the tool joints, reduces casing wear, and reduces the frictional drag of the pipe rotating and sliding in the hole. Sometimes, hardbanding is applied to the pin as well as the box.
References: 1. Drilling Equipment and Operation.
2. drilling Operation.
Gravitational, Magnetic, Radioactive and Thermal are depend on the rock inherent properties Like (Density, Magnetism, temperature and radioactive properties) —-Passive
Electric–natural Currents or Artificial Electrical Source—passive
Seismic-Artificial Source of Energy —Active
The Gravity Method:
The weight of any body depends on the force of gravity at the spot.
The force of gravity various with elevation, rock density, latitude, and topography.
A mass suspended from spring, the amount of spring stretching is proportional to the force of gravity.
F=m . g
g: Acceleration of gravity.
since mass is constant, then stretch variations determine the variations in the acceleration of gravity (g).
The GRAVIMETER instrument used to measure (g) at stations. The readings are corrected for elevation, latitude and topography. The normal value of (g) subtracted from the corrected readings to compute the residual gravity. the values of residual gravity are plotted to the measuring stations to produce contour map of equal residuals.
The case in the middle is normal. In the left the basement rocks (denser) are deeper and sedimentary rocks (low density) thicker, the stretching of spring is less than normal. In the left the basement rocks near surface and the spring stretching is greater than normal.
The value of g at sea level= 980 cm/s2 Closed contours represent the gravity anomalies may be denote a subsurface geological structure. The residual gravity are measured in Gal (Galileo) =1cm/s2 Gal= 1000 milliGal (mGal).
Depict the gravity anomalies map in the figure? And explain the type and the size of subsurface structure?
Depict the gravity anomalies map in the figure? And explain the type and the size of subsurface structure?
Geophysics
The Magnetic Method: The local magnetic variation in the magnetic fields when the basement complexes near the surface and where concentrations of ferromagnetic minerals exist. Magnetometers are the instruments used to measure the earth’s magnetic field. This instruments measure the intensity or field strength Of the Earth’s field. This measured in Tesla (T) and Nano Tesla (nT) or (ϒ) 1ϒ= 10-9 T Nowadays, most magnetic survey are made from airplanes the magnetic intensity are recorded the readings are corrected (from annual magnetic and other variations) Residual field= corrected magnetometer reading- theoretical values the residual are plotted on a map and contours of equal gammas are drawing Closed contours indicate Magnetic anomalies.
