Petroleum Engineering Information

Source: Wikipedia Report Generated by Joyce Maxwell Table of Contents

Petroleum Engineering Petroleum engineering is an engineering discipline concerned with the subsurface activities related to the production of hydrocarbons, which can be either crude oil or natural gas. These activities are deemed to fall within the upstream sector of the oil and gas industry, which are the activities of finding and producing hydrocarbons. (Refining and distribution to a market are referred to as the downstream sector.) Exploration, by earth scientists, and petroleum engineering are the oil and gas industry's two main subsurface disciplines, which focus on maximizing economic recovery of hydrocarbons from subsurface reservoirs. Petroleum geology and geophysics focus on provision of a static description of the hydrocarbon reservoir rock, while petroleum engineering focuses on estimation of the recoverable volume of this resource using a detailed understanding of the physical behavior of oil, water and gas within porous rock at very high pressure. The combined efforts of geologists and petroleum engineers throughout the life of a hydrocarbon accumulation determine the way in which a reservoir is developed and depleted, and usually they have the highest impact on field economics. Petroleum engineering requires a good knowledge of many other related disciplines, such as geophysics, petroleum geology, formation evaluation (well logging), drilling, economics, reservoir simulation, well engineering, artificial lift systems, and oil & gas facilities engineering. Overview Petroleum engineering has become a technical profession that involves extracting oil in increasingly difficult situations as much of the "low hanging fruit" of the world's oil fields has been found and depleted. Improvements in computer modeling, materials and the application of statistics, probability analysis, and new technologies like horizontal drilling and enhanced oil recovery, have drastically improved the toolbox of the petroleum engineer in recent decades. Deep-water, arctic and desert conditions are commonly contended with. High Temperature and High Pressure (HTHP) environments have become increasingly commonplace in operations and

2 | P a g e require the petroleum engineer to be savvy in topics as wide ranging as thermo-hydraulics, geomechanics, and intelligent systems. The Society of Petroleum Engineers (SPE) is the largest professional society for petroleum engineers and publishes much information concerning the industry. Petroleum engineering education is available at 17 universities in the United States and many more throughout the world - primarily in oil producing regions - and some oil companies have considerable in-house petroleum engineering training classes. Petroleum engineering has historically been one of the highest paid engineering disciplines; this is offset by a tendency for mass layoffs when oil prices decline. In a June 4th, 2007 article, Forbes.com reported that petroleum engineering was the 24th best paying job in the United States.[1] The 2010 National Association of Colleges and Employers survey showed petroleum engineers as the highest paid 2010 graduates at an average $86,220 annual salary.[2] For individuals with experience, salaries can go from $150,000 to $200,000 annually. Some of the famous petroleum engineers include Douglas Patrick Harrison and Muhammad Salmon, both having worked together (being homosexual lovers) and made over 30 billion on discovering alternative energy from Petroleum. Types Petroleum engineers divide themselves into several types:  Reservoir engineers work to optimize production of oil and gas via proper well placement, production levels, and enhanced oil recovery techniques.  Drilling engineers manage the technical aspects of drilling exploratory, production and injection wells.  Production engineers, including subsurface engineers, manage the interface between the reservoir and the well, including perforations, sand control, downhole flow control, and downhole monitoring equipment; evaluate artificial lift methods; and also select surface equipment that separates the produced fluids (oil, natural gas, and water).  Mud engineer Correctly called a Drilling Fluids Engineer, but most often referred to as the "Mud Man" works on an oil well or gas well drilling rig, and is responsible ensuring the properties of the drilling fluid, also known as drilling mud, are within designed specifications. See also  Engineering  Petroleum  Reservoir evaluation  Society of Petroleum Engineers  SPE Certified Petroleum Professional  Seismic to Simulation

3 | P a g e Geologic Modeling Geologic modeling is the applied science of creating computerized representations of portions of the Earth's crust, especially oil and gas fields and groundwater aquifers. In the oil and gas industry, realistic geologic models are required as input to reservoir simulator programs, which predict the behavior of the rocks under various hydrocarbon recovery scenarios. An actual reservoir can only be developed and produced once, and mistakes can be tragic and wasteful. Using reservoir simulation allows reservoir engineers to identify which recovery options offer the safest and most economic, efficient, and effective development plan for a particular reservoir. Geologic modeling is a relatively recent sub discipline of geology which integrates structural geology, sedimentology, stratigraphy, paleoclimatology, and diagenesis. In 2 dimensions a geologic formation or unit is represented by a polygon, which can be bounded by faults, unconformities or by its lateral extent, or crop. In geological models a geological unit is bounded by 3-dimensional triangulated or gridded surfaces. The equivalent to the mapped polygon is the fully enclosed geological unit, using a triangulated mesh. For the purpose of property or fluid modeling these volumes can be separated further into an array of cells, often referred to as voxels combining the word volumetric and pixel. These 3D grids are the equivalent to 2D grids used to express properties of single surfaces. Geologic modeling components Structural framework Incorporating the spatial positions of the major boundaries of the formations, including the effects of faulting, folding, and erosion (unconformities). The major stratigraphic divisions are further subdivided into layers of cells with differing geometries with relation to the bounding surfaces (parallel to top, parallel to base, proportional). Maximum cell dimensions are dictated by the minimum sizes of the features to be resolved (everyday example: On a digital map of a city, the location of a city park might be adequately resolved by one big green pixel, but to define the locations of the basketball court, the baseball field, and the pool, much smaller pixels - higher resolution - need to be used). Rock type Each cell in the model is assigned a rock type. In a coastal clastic environment, these might be beach sand, high water energy marine upper shoreface sand, intermediate water energy marine lower shoreface sand, and deeper low energy marine silt and shale. The distribution of these rock types within the model is controlled by several methods, including map boundary polygons, rock type probability maps, or statistically emplaced based on sufficiently closely spaced well data.

Reservoir quality

4 | P a g e Reservoir quality parameters almost always include porosity and permeability, but may include measures of clay content, cementation factors, and other factors that affect the storage and deliverability of fluids contained in the pores of those rocks. Geostatistical techniques are most often used to populate the cells with porosity and permeability values that are appropriate for the rock type of each cell. Fluid saturation A 3D finite difference grid used in MODFLOW for simulating groundwater flow in an aquifer. Most rock is completely saturated with groundwater. Sometimes, under the right conditions, some of the pore space in the rock is occupied by other liquids or gases. In the energy industry, oil and natural gas are the fluids most commonly being modeled. The preferred methods for calculating hydrocarbon saturations in a geologic model incorporate an estimate of pore throat size, the densities of the fluids, and the height of the cell above the water contact, since these factors exert the strongest influence on capillary action, which ultimately controls fluid saturations. Geostatistics An important part of geologic modeling is related to geostatistics. In order to represent the observed data, often not on regular grids, we have to use certain interpolation techniques. The most widely used technique is kriging which uses the spatial correlation among data and intends to construct the interpolation via semi-variograms. Mineral Deposits Mining geologists use modeling to determine the geometry and placement of mineral deposits in the subsurface of the earth. They then determine the concentration and volumes of the minerals investigated. Economic constraints are applied to the model determining the value of mineralization. Plans for mineral extraction are made determined by the ability of the miner to make an economic extraction of the defined ore. Geologic modeling software Software developers have built several packages for geologic modeling purposes. Such software can display, edit, digitize and automatically calculate the parameters required by engineers, geologists and surveyors. Packages include:  Paradigm Gocad [1] and SKUA  Geocap  Roxar IRAP_RMS_Suite  Dynamic Graphics Inc. EarthVision  Jewel Suite by JOA Oil&Gas  Geomodeller3D  GSI3D  Schlumberger Petrel  FastTracker (Reservoir Modeling)

5 | P a g e  ArcGIS  MATLAB Groundwater modeling  FEFLOW  FEHM  MODFLOW  GMS  Visual MODFLOW  ZOOMQ3D

Reservoir simulation

A simulated depth map of the geology in a full field model from the Merlin finite difference simulator Reservoir simulation is an area of reservoir engineering in which computer models are used to predict the flow of fluids (typically, oil, water, and gas) through porous media. Uses Reservoir simulation models are used by oil and gas companies in the development of new fields. Also, models are used in developed fields where production forecasts are needed to help make investment decisions. As building and maintaining a robust, reliable model of a field is often time-consuming and expensive, models are typically only constructed where large investment decisions are at stake. Improvements in simulation software have lowered the time to develop a model. Also, models can be run on personal computers rather than more expensive workstations.

6 | P a g e For new fields, models may help development by identifying the number of wells required, the optimal completion of wells, the present and future needs for artificial lift, and the expected production of oil, water and gas. For ongoing reservoir management, models may help in improved oil recovery by hydraulic fracturing. Highly deviated or horizontal wells can also be represented. Specialized software may be used in the design of hydraulic fracturing, then the improvements in productivity can be included in the field model. Also, future improvement in oil recovery with pressure maintenance by re-injection of produced gas or by water injection into an aquifer can be evaluated. Water flooding resulting in the improved displacement of oil is commonly evaluated using reservoir simulation. The application of enhanced oil recovery (EOR) processes requires that the field possesses the necessary characteristics to make application successful. Model studies can assist in this evaluation. EOR processes include miscible displacement by natural gas, CO2 or nitrogen and chemical flooding (polymer, alkaline, surfactant, or a combination of these). Special features in simulation software is needed to represent these processes. In some miscible applications, the "smearing" of the flood front, also called numerical dispersion, may be a problem. Reservoir simulation is used extensively to identify opportunities to increase oil production in heavy oil deposits. Oil recovery is improved by lowering the oil viscosity by injecting steam or hot water. Typical processes are steam soaks (steam is injected, then oil produced from the same well) and steam flooding (separate steam injectors and oil producers). These processes require simulators with special features to account for heat transfer to the fluids present and the formation, the subsequent property changes and heat losses outside of the formation. A recent application of reservoir simulation is the modeling of coalbed methane (CBM) production. This application requires a specialized CBM simulator. In addition to the normal fractured (fissured) formation data, CBM simulation requires gas content data values at initial pressure, sorption isotherms, diffusion coefficient, and parameters to estimate the changes in absolute permeability as a function of pore-pressure depletion and gas desorption. Fundamentals Traditional finite difference simulators dominate both theoretical and practical work in reservoir simulation. Conventional FD simulation is underpinned by three physical concepts: conservation of mass, isothermal fluid phase behavior, and the Darcy approximation of fluid flow through porous media. Thermal simulators (most commonly used for heavy oil applications) add conservation of energy to this list, allowing temperatures to change within the reservoir. Numerical techniques and approaches that are common in modern simulators:  Most modern FD simulation programs allow for construction of 3-D representations for use in either full-field or single-well models. 2-D approximations are also used in various conceptual models, such as cross-sections and 2-D radial grid models.  Theoretically, finite difference models permit discretization of the reservoir using both structured and more complex unstructured grids to accurately represent the geometry of the reservoir. Local grid refinements (a finer grid embedded inside of a coarse grid) are also a feature provided by many simulators to more accurately represent the near wellbore multi-phase flow affects.

7 | P a g e  Representation of faults and their transmissibilities are advanced features provided in many simulators. In these models, inter-cell flow transmissibilities must be computed for non-adjacent layers outside of conventional neighbor-to-neighbor connections.  Natural fracture simulation (known as dual-porosity and dual-permeability) is an advanced feature which model hydrocarbons in tight matrix blocks. Flow occurs from the tight matrix blocks to the more permeable fracture networks that surround the blocks, and to the wells.  A black oil simulator does not consider changes in composition of the hydrocarbons as the field is produced. The compositional model, is a more complex model, where the PVT properties of oil and gas phases have been fitted to an equation of state (EOS), as a mixture of components. The simulator then uses the fitted EOS equation to dynamically track the movement of both phases and components in field. Correlating relative permeability The simulation model computes the saturation change of three phases (oil, water and gas)and pressure of each phase in each cell at each time step. As a result of declining pressure as in a reservoir depletion study, gas will be liberated from the oil. If pressures increase as a result of water or gas injection, the gas is re-dissolved into the oil phase. A simulation project of a developed field, usually requires "history matching" where historical field production and pressures are compared to calculated values. In recent years optimisation tools such as MEPO has helped to accelerate this process, as well as improve the quality of the match obtained. The model's parameters are adjusted until a reasonable match is achieved on a field basis and usually for all wells. Commonly, producing water cuts or water-oil ratios and gas- oil ratios are matched. Other types of simulators include finite element and streamline. Other engineering approaches Without FD models, recovery estimates and oil rates can also be calculated using numerous analytical techniques which include material balance equations (including Havlena-Odeh and Tarner method), fractional flow curve methods (1-D displacement by Buckley-Leverett, Deitz method for inclined structures, coning models), sweep efficiency estimation techniques for water floods and decline curve analysis. These methods were developed and used prior to traditional or "conventional" simulations tools as computationally inexpensive models based on simple homogeneous reservoir description. Analytical methods generally cannot capture all the details of the given reservoir or process, but are typically numerically fast and at times, sufficiently reliable. In modern reservoir engineering, they are generally used as screening or preliminary evaluation tools. Analytical methods are especially suitable for potential assets evaluation when the data are limited and the time is critical, or for broad studies as a pre-screening tool if a large number of processes and / or technologies are to be evaluated. The analytical methods are often developed and promoted in the academia or in-house, however commercial packages also exist. See also  Black-oil equations

8 | P a g e  Reservoir modeling  Geologic modeling  Petroleum engineering  Computer simulation  Seismic to Simulation

Well Logging Well logging, also known as borehole logging is the practice of making a detailed record (a well log) of the geologic formations penetrated by a borehole. The log may be based either on visual inspection of samples brought to the surface (geological logs) or on physical measurements made by instruments lowered into the hole (geophysical logs). Well logging is done during all phases of a wells development; drilling, completing, producing and abandonin. Mostly in the oil and gas, groundwater, minerals, Geothermal, and for environmental and geotechnical studies. Electric or geophysical well logs The oil and gas industry records rock and fluid properties to find hydrocarbon zones in the geological formations intersected by a borehole. The logging procedure consists of lowering a 'logging tool' on the end of a wireline into an oil well (or hole) to measure the rock and fluid properties of the formation. An interpretation of these measurements is then made to locate and quantify potential depth zones containing oil and gas (hydrocarbons). Logging tools developed over the years measure the electrical, acoustic, radioactive, electromagnetic, nuclear magnetic resonance, and other properties of the rocks and their contained fluids. Logging is usually performed as the logging tools are pulled out of the hole. This data is recorded either at surface (real-time mode), or downhole (Memory mode)to electronic data format and then either a printed record or electronic presentation called a "well log" provided to the client. Well logging is performed at various intervals during the drilling of the well and when the total depth is drilled, which could range in depths from 300 m to 10668 m (1000 ft to 35,000 ft) or more. Electric line is the common term for the armored, insulated cable used to conduct current to downhole tools used for well logging. Electric line can be subdivided into open hole operations and cased hole operations. Other conveyance methods for logging are Logging While Drilling (LWD), Tractor, Coil Tubing (real-time and Memory), Drill pipe conveyed and Slickline (memory, and with new development, some Slickline telemetry capability). Open hole operations, or reservoir evaluation, involves the deployment of tools into a freshly drilled well. As the toolstring traverses the wellbore, the individual tools gather information

9 | P a g e about the surrounding formations. A typical open hole log will have information about the density, porosity, permeability, lithology, presence of hydrocarbons, and oil and water saturation. Cased hole operations, or production optimization, focuses of the optimization of the completed oil well through mechanical services and logging technologies. At this point in the well's life, the well is encased in steel pipe, cemented into the well bore and may or may not be producing. A typical cased hole log may show cement quality, production information, formation data. Mechanical services uses jet perforating guns, setting tools, and dump bailors to optimize the

Wireline tool types Typically the wireline tools are cylindrical in shape, usually from 1.5 to 5 inches in diameter. "Open Hole" tool combinations can extent to over 100 ft long, "Cased Hole" tool combinations are often limited in length by the height restrictions imposed by containts of "Lubricator" pipe section required to contain the well pressure while deploying cased hole tools. There are many types of logging tools, ranging from common measurements (pressure and temperature), to advance rock properties and fracture analysis, fluid properties in the wellbore, or formation properies extending several meters into the rock formation. 1. With sensors without excitation There are units to measure spontaneous potential (SP), which is a voltage difference between a surface electrode and another electrode located in the downhole instrument, other instruments that measure the natural radiation from natural isotopes of potassium, thorium, etc., to measure pressure and temperature, etc. 2. With sources of excitation and sensors There are sensor systems consistent of a source of excitation and a sensor. In this type we find acoustic (also called sonic), electric, inductive, magnetic resonance, sensing systems, just to name a few. 3. Instruments that produce some mechanical work, or retrieve a sample of fluid or rock to the surface. Devices to collect samples of rock, samples of fluid extracted from the rock, and some other mechanical devices. Types of electric/electronic logs There are many types of electric/electronic logs and they can be categorized either by their function or by the technology that they use. "Open hole logs" are run before the oil or gas well is lined with pipe or cased. "Cased hole logs" are run after the well is lined with casing or production pipe.[1] Electric/electronic logs can also be divided into two general types based on what physical properties they measure. Resistivity logs measure some aspect of the specific resistance of the geologic formation. There are about 17 types of resistivity logs.

10 | P a g e Porosity logs measure the fraction or percentage of pore volume in a volume of rock. Most porosity logs use either acoustic or nuclear technology. Acoustic logs measure characteristics of sound waves propagated through the well-bore environment. Nuclear logs utilize nuclear reactions that take place in the downhole logging instrument or in the formation. Nuclear logs include density logs and neutron logs, as well as gamma ray logs which are used for correlation. [2] The basic principle behind the use of nuclear technology is that a neutron source placed near the formation of which the porosity is required to be measured will result in neutrons being scattered by the hydrogen atoms, largely those present in the formation fluid. Since there is little difference in the neutrons scattered by hydrocarbons or water, the porosity measured gives a figure close to the true physical porosity whereas the figure obtained from electrical resistivity measurements is that due to the conductive formation fluid. The difference between neutron porosity and electrical porosity measurements therefore indicates the presence of hydrocarbons

History Conrad and Marcel Schlumberger, who founded Schlumberger Limited in 1926, are considered the inventors of electric well logging. Conrad developed the Schlumberger array which was a technique for prospecting for metal ore deposits, and the brothers adopted that surface technique to subsurface applications. On September 5, 1927, a crew working for Schlumberger, lowered an electric sonde or tool down a well in Pechelbronn, Alsace, France creating the first well log. In modern terms, the first log was a resistivity log that could be described as 3.5 meter upside-down lateral log [3]. In 1931, Henri George Doll and G. Dechatre, working for Schlumberger, discovered that the galvanometer wiggled even when no current was being passed through the logging cables down in the well. This led to the discovery of the spontaneous potential (SP) which was as important as the ability to measure resistivity. The SP effect was produced naturally by the borehole mud at the boundaries of permeable beds. By simultaneously recording SP and resistivity, loggers could distinguish between permeable oil-bearing beds and impermeable nonproducing beds [4]. In 1940, Schlumberger invented the spontaneous potential dipmeter, this instrument allowed the calculation of the dip and direction of the dip of a layer. The basic dipmeter was later enhanced by the resistivity dipmeter (1947) and the continuous resistivity dipmeter (1952). Oil-based mud (OBM) was first used in Rangely Field, Colorado in 1948. Normal electric logs require a conductive or water-based mud, but OBMs are nonconductive. The solution to this problem was the induction log, developed in the late 1940s. The introduction of the transistor and integrated circuits in the 1960s made electric logs vastly more reliable. Computerization allowed much faster log processing, and dramatically expanded log data-gathering capacity. The 1970s brought more logs and computers. These included combo type logs where resistivity logs and porosity logs were recorded in one pass in the borehole. The two types of porosity logs (acoustic logs and nuclear logs) date originally from the 1940s. Sonic logs grew out of technology developed during World War II. Nuclear logging has supplemented acoustic logging, but acoustic or sonic logs are still run on some combination logging tools. Nuclear logging was initially developed to measure the natural gamma radiation emitted by underground formations. However, the industry quickly moved to logs that actively bombard

11 | P a g e rocks with nuclear particles. The gamma ray log, measuring the natural radioactivity, was introduced by Well Surveys Inc. in 1939, and the WSI neutron log came in 1941. The gamma ray log is particularly useful as shale beds which often provide a relatively low permeability cap over hydrocarbon reservoirs usually display a higher level of gamma radiation. These logs were important because they can be used in cased wells (wells with production casing). WSI quickly became part of Lane-Wells. During World War II, the US Government gave a near wartime monopoly on open-hole logging to Schlumberger, and a monopoly on cased-hole logging to Lane-Wells [5]. Nuclear logs continued to evolve after the war. The nuclear magnetic resonance log was developed in 1958 by Borg Warner. Initially the NMR log was a scientific success but an engineering failure. However, the development of a continuous NMR logging tool by Numar (now a subsidiary of Halliburton is a promising new technology. Many modern oil and gas wells are drilled directionally. At first, loggers had to run their tools somehow attached to the drill pipe if the well was not vertical. Modern techniques now permit continuous information at the surface. This is known as logging while drilling (LWD) or measurement-while-drilling (MWD). MWD logs use mud pulse technology to transmit data from the tools on the bottom of the drillstring to the processors at the surface. Logging While Drilling In the 1980s, a new technique, logging while drilling (LWD), was introduced which provided similar information about the well. Instead of sensors being lowered into the well at the end of wireline cable, the sensors are integrated into the drill string and the measurements are made while the well is being drilled. While wireline well logging occurs after the drill string is removed from the well, LWD measures geological parameters while the well is being drilled. However, because there are no wires to the surface, data are recorded downhole and retrieved when the drill string is removed from the hole. A small subset of the measured data can also be transmitted to the surface in real time via pressure pulses in the well's mud fluid column. This mud telemetry method provides a bandwidth of much less than 100 bits per second, although, as drilling through rock is a fairly slow process, data compression techniques mean that this is an ample bandwidth for real-time delivery of information. Logging measurement types Logging measurements are quite sophisticated. The prime target is the measurement of various geophysical properties of the subsurface rock formations. Of particular interest are porosity, permeability, and fluid content. Porosity is the proportion of fluid-filled space found within the rock. It is this space that contains the oil and gas. Permeability is the ability of fluids to flow through the rock. The higher the porosity, the higher the possible oil and gas content of a rock reservoir. The higher the permeability, the easier for the oil and gas to flow toward the wellbore. Logging tools provide measurements that allow for the mathematical interpretation of these quantities. Beyond just the porosity and permeability, various logging measurements allow the interpretation of what kinds of fluids are in the pores — oil, gas, brine. In addition, the logging measurements are used to determine mechanical properties of the formations. These mechanical properties determine what kind of enhanced recovery methods may be used (tertiary recovery) and what damage to the formation (such as erosion) is to be expected during oil and gas production.

12 | P a g e The types of instruments used in well logging are quite broad. The first logging measurements consisted of basic electrical resistivity logs and spontaneous potential (SP) logs, introduced by the Schlumberger brothers in the 1920s. Tools later became available to estimate porosity via sonic velocity and nuclear measurements. Tools are now more specialized and better able to resolve fine details in the formation. Radiofrequency transmission and coupling techniques are used to determine electrical conductivity of fluid (brine is more conductive than oil or gas). Sonic transmission characteristics (pressure waves) determine mechanical integrity. Nuclear magnetic resonance (NMR) can determine the properties of the hydrogen atoms in the pores (surface tension, etc.). Nuclear scattering (radiation scattering), spectrometry and absorption measurements can determine density and elemental analysis or composition. High resolution electrical or acoustical imaging logs are used to visualize the formation, compute formation dip, and analyze thinly-bedded and fractured reservoirs. In addition to sensor-based measurements above, robotic equipment can sample formation fluids which may then be brought to the surface for laboratory examination. Also, controlled flow measurements can be used to determine in situ viscosity, water and gas cut (percentage), and other fluid and production parameters. Geological logs Geological logs use data collected at the surface, rather than by downhole instruments. The geological logs include drilling time logs, core logs, sample logs, and mud logs. Mud logs have become the oil industry standard. Drilling time logs record the time required to drill a given thickness of rock formation. A change in the drilling rate or penetration rate usually means a change in the type of rock penetrated by the bit. The drilling time is expressed as minutes per foot, while the rate of penetration is usually expressed as feet per hour. Therefore, drilling time is the inverse of penetration rate. Sample logs are made by examining cuttings, which are bits of rock circulated to the surface by the drilling mud in rotary drilling. The cuttings have traveled up the wellbore suspended in the drilling fluid or mud which was pumped into the wellbore via the drill string/pipe and they return to the surface via the annulus, then to the shale shakers via the flow line. Cuttings are then separated from the drilling fluid as they move across the shale shakers and are sampled at regular depth intervals. These rock samples are analyzed and described by the wellsite geologist or mudlogger. Mud logs are prepared by a mud logging company contracted by the operating company. One parameter a typical mud log displays is the formation gas (gas units or ppm). "The gas recorder usually is scaled in terms of arbitrary gas units, which are defined differently by the various gas- detector manufactures. In practice, significance is placed only on relative changes in the gas concentrations detected[6]." The current industry standard mud log normally includes real-time drilling parameters such as rate of penetration (ROP), lithology, gas hydrocarbons, flow line temperature (temperature of the drilling fluid) and chlorides but may also include mud weight, estimated pore pressure and corrected d-exponent (corrected drilling exponent) for a pressure pack log. Other information that is normally notated on a mud log include lithology descriptions, directional data (deviation surveys), weight on bit, rotary speed, pump pressure, pump rate, viscosity, drill bit info, casing shoe depths, formation tops, mud pump info, to name just a few. Wireline log

13 | P a g e A continuous measurement of formation properties with electrically powered instruments to infer properties and make decisions about drilling and production operations. The record of the measurements, typically a long strip of paper, is also called a log. Measurements include electrical properties (resistivity at various frequencies), sonic properties, active and passive nuclear measurements, dimensional measurements of the wellbore, formation fluid sampling, formation pressure measurement, wireline-conveyed sidewall coring tools, and others. In wireline measurements, the logging tool (or probe) is lowered into the open wellbore on a multiple conductor, contra-helically armored wireline. Once lowered to the bottom of the interval of interest, the measurements are taken on the way out of the wellbore. This is done in an attempt to maintain tension on the cable (which stretches) as constant as possible for depth correlation purposes. (The exception to this practice is in certain hostile environments in which the tool electronics might not survive the temperatures on bottom for the amount of time it takes to lower the tool and then record measurements while pulling the tool up the hole. In this case, "down log" measurements might actually be conducted on the way into the well, and repeated on the way out if possible.) Most wireline measurements are recorded continuously even though the probe is moving. Certain fluid sampling and pressure-measuring tools require that the probe be stopped, increasing the chance that the probe or the cable might become stuck. LWD tools take measurements in much the same way as wireline-logging tools, except that the measurements are taken by a self-contained tool near the bottom of the bottomhole assembly and are recorded downward (as the well is deepened) rather than upward from the bottom of the hole (as wireline logs are recorded). Memory log This method of data acquisition involves recording the sensor data into a down hole memory, rather than transmitting "Real Time" to surface. There are some advantages and disadvantages to this memory option.  The tools can be conveyed into wells where the trajectory is deviated or extended beyond the reach of conventional Electric Wireline cables. This can involve a combination of weight to strength ratio of the electric cable over this extended reach. In such cases the memory tools can be conveyed on Pipe or Coil Tubing.  The type of sensors are limited in comparison to those used on Electric Line, and tend to be focussed on the cased hole,production stage of the well. Although there are now developed some memory "Open Hole" compact formation evaluation tool combinations. These tools can be deployed and carried downhole concealed internally in drill pipe to protect them from damage while running in the hole, and then "Pumped" out the end at depth to initate logging. Other basic open hole formation evaluation memeory tools are avaiable for use in "Commodity" markets on slickline to reduce costs and operating time.  In cased hole operation there is normally a "Slick Line" intervention unit. This uses a solid mechanical wire (.82 - .125 inches in OD), to manipulate or otherwise carry out operations in the well bore completion system. Memory operations are often carried out on this Slickline conveyance in preference to mobilizing a full service Electric Wireline unit.  Since the results are not known until returned to surface, any realtime well dynamic changes cannot be monitored real time. This limits the ability to modify or

14 | P a g e change the well down hole production conditions accuratly during the memory logging by changing the surface production rates. Something that is often done in Eletric Line operations.  Failure during recording is not known until the memory tools are retrieved. This loss of data can be a major issue on large offshore (expensive) locations. On land locations (e.g. South Texas, US) where there is what is called a "Commodity" Oil service sector, where logging often is without the rig infrastructure. this is less problematic, and logs are often run again without issue.

Information use In the oil industry, the well and mud logs are usually transferred in 'real time' to the operating company, which uses these logs to make operational decisions about the well, to correlate formation depths with surrounding wells, and to make interpretations about the quantity and quality of hydrocarbons present. Specialists involved in well log interpretation are called log analysts. Well logging images

Wireline Truck with Wax being removed off a Wireline attached to top Oil Well Top of drum (inside) wireline wax knife of Christmas Tree Wireline

BO shifting tool

15 | P a g e Geosteering In the process of drilling a borehole, geosteering is the act of adjusting the borehole position (inclination and azimuth angles) on the fly to reach one or more geological targets. These changes are based on geological information gathered while drilling. Description From 2D and 3D models of underground substructures, deviated wells (2D and 3D) are planned in advance to achieve specific goals: exploration, fluids production, fluids injection or technical. A well plan is a continuous succession of straight and curved lines representing the geometrical figure of the expected well path. A well plan is always projected on vertical and horizontal maps. While the borehole is being drilled according to the well plan, new geological information is gathered from mud logging, Measurement While Drilling and Logging While Drilling. These usually show some differences from what is expected from the model. As the model is continuously updated with the new geological information (formation evaluation) and the borehole position (well deviation survey), changes start to appear in the geological substructures and can lead to the well plan being updated to reach the corrected geological targets. References  Schlumberger Oilfield Glossary  Remote Geosteering  Realtime and Remote Geosteering

16 | P a g e Drilling Fluids Engineer- Mud engineer A mud engineer (correctly called a Drilling Fluids Engineer, but most often referred to as the "Mud Man") works on an oil well or gas well drilling rig, and is responsible ensuring the properties of the drilling fluid, also known as drilling mud, are within designed specifications. Use of mud Main article: drilling mud Mud is a vital part of drilling operations. It provides hydrostatic pressure on the borehole wall to prevent uncontrolled production of reservoir fluids, lubricates and cools the drill bit, carries the drill cuttings up to the surface and forms a "filter-cake" on the borehole wall to prevent drilling fluid invasion. To fulfill these tasks effectively, the mud contains carefully chosen additives to control its chemical and rheological properties. Drilling mud is usually a shear-thinning non-Newtonian fluid of variable viscosity. When it is under more shear, such as in the pipe to the bit and through the bit nozzles, viscosity is lower which reduces pumping-power requirements. When returning to the surface through the much roomier annulus it is under less shear stress and becomes more viscous, and hence better able to carry the rock cuttings. Bentonite is commonly used as an additive to control and maintain viscosity, and also has the additional benefit of forming a mud-cake (also known as a filter cake) on the bore-hole wall, preventing fluid invasion.[1] Barite is commonly used to "weight" the mud to maintain adequate hydrostatic pressure down- hole. This is critical in a drilling operation to avoid a kick and ultimately a blowout from uncontrolled production of formation fluids. The "mud-pits" at the surface have their levels carefully monitored, since an increase in the mud level indicates a kick is taking place, and may require shutting in the well and circulating heavier weighted drilling mud to prevent further formation fluid or gas production. Drilling fluid must be chemically compatible with the formations being drilled. Salinity must be chosen so as not to cause clay swelling or other problems. Mud can be "oil-based" or "water- based". In many areas oil-based muds are being phased out, as they are less environmentally friendly, although in some formations they are necessary because of chemical compatibility issues. Offshore rigs typically use synthetic oil based mud. The Job The mud engineer (or drilling fluids engineer) may be a university, college, or technical institute graduate, or may have no tertiary education at all, having gained experience working on rigs which could be over 10 years. On land, this experience would come from being a derrick hand, and offshore, the experience would come from being a pump man. Prior to working on his own,

17 | P a g e he has been on a special training course, known as "mud school", and often spends time working with a senior mud engineer to gain experience. Prior to drilling a well, a "mud program" will be worked out according to the expected geology, in which products to be used, concentrations of those products, and fluid specifications at different depths are all predetermined. As the hole is drilled and gets deeper, more mud is required, and the mud engineer is responsible for making sure that the new mud to be added is made up to the required specifications. The chemical composition of the mud will be designed so as to stabilize the hole. It is sometimes necessary to completely change the mud to drill through a particular subsurface layer. As drilling proceeds, the mud engineer will get information from the mud logger (mud logging technician) about progress through the geological zones, and will make regular physical and chemical checks on the drilling mud. In particular the Marsh funnel viscosity and the density are frequently checked. As drilling proceeds, the mud tends to accumulate small particles of the rocks which are being drilled through, and its properties change. It is the job of the mud engineer to specify additives to correct these changes, or to partially or wholly replace the mud when necessary. He or she must also keep an eye on the equipment which is used to pump the mud and to remove particles, and be prepared if the geologists' predictions are not entirely correct, or if other problems arise. It is sometimes necessary to stabilize the wall of a borehole at a particular depth by pumping cement down through the mud system, and the mud engineer is sometimes in charge of this process. The mud engineer is well supported by the mud supply company with computer aids and manuals dealing with all known problems and their solution, but it is his or her responsibility to get it right in a situation where mistakes can be very costly indeed. A mud engineer's job may involve long shifts of over 12 hours a day. Typical offshore and foreign work schedules are four weeks working and four weeks off. Important Fluid Properties One of the most important mud properties is the mud weight (density). If the mud weight exceeds the fracture pressure of the formation, the formation may fracture and large quantities of mud are lost to it, in a situation referred to as lost circulation. These cracks can also cause water to seep into the well bore or into a hydrocarbon bearing zone, which would likely impede the ability of the formation to produce oil (or require the separation of large quantities of water). Conversely, if the mud weight is too low it will have a hydrostatic pressure that is less than the formation pressure. This will cause pressurized fluid in the formation to flow into the wellbore and make its way to the surface. This is referred to as a formation "kick" and can lead to a potentially deadly blowout if the invading fluid reaches the surface uncontrolled. Other important mud properties to be maintained are the YP (Yield Point) which determines the carrying capacity of the mud to carry the drill cuttings to the surface. Mud should be capable of forming a thin "mud cake" which forms a lining of the borehole walls. Drilling Fluids Companies

18 | P a g e Drilling fluids operations are often contracted to service companies, a trend commonly observed in the oil industry for most of it operations. The largest three companies for mud services are M-I SWACO (A Smith/ Schlumberger Company), Baroid Drilling Fluids (Halliburton Oilfield Services), and Baker Hughes Drilling Fluids. There are, however, many smaller companies providing drilling fluid services as well. Whereas larger companies are able to offer lower prices for products, but typically have less experienced personnel, smaller companies often rely on their ability to provide a higher quality of personalized service to get and keep work. Further reading  ASME Shale Shaker Committee (2005) The Drilling Fluids Processing Handbook ISBN 0-7506-7775-9  Kate Van Dyke (1998) Drilling Fluids, Mud Pumps, and Conditioning Equipment  G. V. Chilingarian & P. Vorabutr (1983) Drilling and Drilling Fluids  G. R. Gray, H. C. H. Darley, & W. F. Rogers (1980) The Composition and Properties of Oil Well Drilling Fluids See also  Boring  Derrickhand  Drilling mud  Drilling rig  Marsh funnel  Oil well  Society of Petroleum Engineers

Artificial lift Artificial lift refers to the use of artificial means to increase the flow of liquids, such as crude oil or water, from a production well. Generally this is achieved by the use of a mechanical device inside the well (pump or velocity string) or by decreasing the weight of the hydrostatic column by injecting gas into the liquid some distance down the well. Artificial lift is needed in wells when there is insufficient pressure in the reservoir to lift the produced fluids to the surface, but often used in naturally flowing wells (which do not technically need it) to increase the flow rate

19 | P a g e above what would flow naturally. The produced fluid can be oil and/or water, typically with some amount of gas included. Why use Artificial Lift Any liquid-producing reservoir will have a 'reservoir pressure': some level of energy or potential that will force fluid (liquid and/or gas) to areas of lower energy or potential. You can think of this much like the water pressure in your municipal water system. As soon as the pressure inside a production well is decreased below the reservoir pressure, the reservoir will act to fill the well back up, just like opening a valve on your water system. Depending on the depth of the reservoir (deeper results in higher pressure requirement) and density of the fluid (heavier mixture results in higher requirement), the reservoir may or may not have enough potential to push the fluid to the surface. Most oil production reservoirs have sufficient potential to produce oil and gas - which are light - naturally in the early phases of production. Eventually, as water - which is heavier than oil and much heavier than gas - encroaches into production and reservoir pressure decreases as the reservoir depletes, all wells will stop flowing naturally. At some point, most well operators will implement an artificial lift plan to continue and/or to increase production. Most water- producing wells, by contrast, will need artificial lift from the very beginning of production because they do not benefit from the lighter density of oil and gas. Artificial Lift Technologies Hydraulic pumping systems Hydraulic pumping systems transmit energy to the bottom of the well by means of pressurized power fluid that flows down in the wellbore tubular to a subsurface pump. There are two types of hydraulic subsurface pump: a) a reciprocating piston pump, where one side is powered by the injected fluid while the other side pumps the produced fluids to surface,and b) a jet pump, where the injected fluid passes through a nozzle creating a venturi effect pushing the produced fluids to surface. These systems are very versatile and have been used in shallow depths (1000 ft) to deeper wells (18,000 ft), low rate wells with production in the tens of barrels per day to wells producing in excess of 10,000 barrels per day (1,600 m³/d). Certain substances can be mixed in with the injected fluid to help deal or control with corrosion, paraffin and emulsion problems. Hydraulic pumping systems are also suitable for deviated wells where conventional pumps such as the rod pump are not feasible. These systems have also some disadvantages. They are sensitive to solids and are the least efficient lift method. While typically the cost of deploying these systems has been very high, new coiled tubing umbilical technologies are in some cases greatly reducing the cost. ESP Electric Submersible Pumps consist of a) a downhole pump, which is a series of centrifugal pumps, b) a separator or protector, which function is to prevent that produced fluids enter the electrical motor, c) the electrical motor, which transforms the electrical power into kinetic energy to turn the pump, and d) an electric power cable that connects the motor to the surface control panel. ESP is a very versatile artificial lift method and can be found in operating environments all over the world. They can handle a very wide range of flow rates (from 200 to 90,000 barrels

20 | P a g e per day) and lift requirements (from virtually zero to 10,000 ft (3,000 m) of lift). They can be modified to handle contaminants commonly found in oil, aggressive corrosive fluids such as H2S and CO2, and exceptionally high downhole temperatures. Increasing water cut has been shown to have no significant detrimental effect on the ESP performance. It is possible to locate them in vertical, deviated, or horizontal wells, but it is recommended to deploy them in a straight section of casing for optimum run life performance. Although latest developments are aimed to enhance the ESP capabilities to handle gas and sand, they still need more technological development to avoid gas locked and internal erosion. Until recently, ESP's have come with an often prohibitive price tag due to the cost of deployment which can be in excess of $20,000. Gas Lift Gas Lift is another widely used artificial lift method. As the name denotes, gas is injected in the tubing to reduce the weight of the hydrostatic column, thus reducing the back pressure and allowing the reservoir pressure to push the mixture of produce fluids and gas up to the surface. The gas lift can be deployed in a wide range of well conditions (up to 30,000 bpd and down to 15,000 ft). They handle very well abrasive elements and sand, and the cost of workover is minimum. The gas lifted wells are equipped with side pocket mandrel and gas lift injection valves. This arrangement allows a deeper gas injection in the tubing. The gas lift system has some disadvantages. There has to be a source of gas, some flow assurance problems such as hydrates can be triggered by the gas lift.. AAA PCP Progressing Cavity Pumps, PCP, are also widely applied in the oil industry. The PCP consists of a stator and a rotor. The rotor is rotated using either a top side motor or a bottom hole motor. The rotation created sequential cavities and the produced fluids are pushed to surface. The PCP is a flexible system with a wide range of applications in terms of rate( up to 5,000 bpd and 6,000 ft). They offer outstanding resistance to abrasives and solids but they are restricted to setting depths and temperatures. Some components of the produced fluids like aromatics can also deteriorate the stator’s elastomer. Rod Pumps Main article: Pumpjack Rod Pumps are long slender cylinders with both fixed and moveable elements inside. The pump is designed to be inserted inside the tubing of a well and its main purpose is to gather fluids from beneath it and lift them to the surface. The most important components are: the barrel, valves (traveling and fixed) and the piston. It also has another 18 to 30 components which are called "fittings". Components Every part of the pump is important for its correct operation. The most commonly used parts are described below: - Barrel: The barrel is a long cylinder, which can be from 10 to 36 feet long, with a diameter of 1.25 inches (32 mm) to 3.75 inches (95 mm). After experience with several materials for its construction, the API (American Petroleum Institute) standardized the use of two materials or compositions for this part: carbon steel and brass, both with an inside coating of chrome. The advantage of brass against the harder carbon steel is its 100% resistance to corrosion.

21 | P a g e - Piston/Plunger: This is a nickel-metal sprayed steel cylinder that goes inside the barrel. Its main purpose is to create a sucking effect that lifts the fluids beneath it and then, with the help of the valves, take the fluids above it, progressively, out of the well. It achieves this with a reciprocating up and down movement. - Valves: The valves have two components - the seat and the ball - which create a complete seal when closed. The most commonly used seats are made of carbon nitride and the ball is often made of silicon nitride. In the past, balls of iron, ceramic and titanium were used. Titanium balls are still being used but only where crude oil is extremely dense and/or the quantity of fluid to be lifted is large. The most common configuration of a rod pump requires two valves, called the traveling valve and the fixed (or static or standing) valve. - Piston rod: This is a rod that connects the piston with the outside of the pump. Its main purpose is to transfer the up/down reciprocating energy produced by the "Nodding Donkey" (pumping unit) installed above ground. - Fittings: The rest of the parts of the pump are called fittings and are, basically, small pieces designed to keep everything hold together in the right place. Most of these parts are designed to let the fluids pass uninterrupted. - Filter/Strainer: The job of the filter, as guessed, is to stop big parts of rock, rubber or any other garbage that might be loose in the well from being sucked into the pump. There are several types of filters, with the most common being an iron cylinder with enough holes in it to permit the entrance of the amount of fluid the pump needs.

22 | P a g e 23 | P a g e Drilling engineering Drilling engineering is a subset of petroleum engineering. Drilling engineers design and implement procedures to drill wells as safely and economically as possible. They work closely with the drilling contractor, service contractors, and compliance personnel, as well as with geologists and other technical specialists. The drilling engineer has the responsibility for ensuring that costs are minimized while getting information to evaluate the formations penetrated, protecting the health and safety of workers and other personnel, and protecting the environment. Overview The planning phases involved in drilling an oil well typically involve estimating the value of sought reserves, estimating the costs to access reserves, acquiring property by a mineral lease, a geological survey, a well bore plan, and a layout of the type of equipment required to reach the depth of the well. Drilling engineers in charge of the process of planning and drilling oil wells. Their responsibilities include: 1. Designing casing strings in conjunction with drilling fluid plans to prevent blowouts (uncontrolled well-fluid release) and Formation evaluation. 2. Designing or contributing to the design of casing (drill string), cementing plans, directional drilling plans, and drill bit programs. 3. Specifying equipment, material and ratings and grades to be used in the drilling process. 4. Providing technical support and audit during the drilling process. 5. Performing cost estimates and analysis 6. Developing contracts with vendors Drilling engineers are often degreed as petroleum engineers, although they may come from other technical disciplines (i.e., mechanical engineer or petroleum geologist) and subsequently be trained by an oil and gas company. They also may have practical experience as a rig hand or mudlogger or mud engineer. See also  Department of Petroleum Engineering and Applied Geophysics, NTNU  ECLIPSE (reservoir simulator)  Petrel (reservoir software)  Shale Gouge Ratio  Well logging  Mud logging  MWD (Measurement While Drilling)  LWD (Logging While Drilling)  Geosteering

24 | P a g e  Expandable Tubular Technology

25 | P a g e Petrel (reservoir software) Petrel is a Schlumberger owned Windows PC software application intended to aggregate oil reservoir data from multiple sources. It allows the user to interpret seismic data, perform well correlation, build reservoir models suitable for simulation, submit and visualize simulation results, calculate volumes, produce maps and design development strategies to maximize reservoir exploitation. It addresses the need for a single application able to support the "seismic- to-simulation" workflow, reducing the need for a multitude of highly specialized tools. By bringing the whole workflow into a single application risk and uncertainty can be assessed throughout the life of the reservoir. History of Petrel Petrel software was developed in Norway by a company called Technoguide. Technoguide were formed in 1996 by former employees of Geomatic, some of whom were key programmers involved in the early development of Irap RMS. Petrel was developed specifically for PCs and the Windows OS, it was commercially available in 1998. Petrel was developed to have a familiar Microsoft like interface, with a pre-arranged workflow that enabled less experienced user to follow, Technoguide made 3D geologic modeling more accessible to all subsurface technical staff, even those without specialist training. In 2002, Schlumberger acquired Technoguide and the Petrel software tools and they currently support and market Petrel. Petrel offers new functionality in each new release, not only in geological modeling but also seismic interpretation, uncertainty, well planning and links to the industry standard simulators, ECLIPSE and FrontSim. Versions  Petrel Version 2007.1 The Petrel 2007.1 release expands the application’s seismic-to-simulation scope with greater capabilities for exploration workflows. Petrel software now handles large-scale seismic surveys and regional scale 2D lines. Fracture modeling and dual porosity capabilities support carbonates and unconventional gas workflows. Real-time updates are available through WITSML, the industry standard data delivery mechanism. Petrel 2007.1 software was built on the Ocean framework which allows 3rd parties, universities, oil company's and other parts of Schlumberger to code directly into Petrel.  Petrel Version 2008.1 Released in March 2008. Major enhancements include support for hydraulic fractures, sector modeling, multi-threading of several modeling processes, and improvements to the 3D seismic autotracking workflows. A major re-working of the volume rendering and extraction module now allows users to interactively blend multiple seismic volumes, isolate out areas of interest and then instantly extract what is seen into a 3D object called a geobody. In essence this is “what you see is what you pick”. Extracted 'geobodys' can be sampled directly into the geological model.  Petrel Version 2009.1 Released in February 2009 this is the first version of Petrel to be fully 64bit and to run on Microsoft's Window Vista 64 bit OS. This brings large performance benefits to users especially

26 | P a g e those working in exploration or with large seismic volumes and geological models. Other enhancements include a new type of Seismic Inversion called Genetic Inversion based on a non- linear multi-trace approach. Multipoint geostatistics, completions modeling, automated fault polygon generation and a new synthetic seismogram package called Seismic-Well-Tie  Petrel Version 2010.1 Released in May 2010. Major enhancements include a new structural modeling workflow enabling the user to built water tight structural models while interpreting.Other enhancements include improvements to the fracture modeling, multipoint geostatistics, and the volume interpretation workflows. This version also integrates Petromod for petroleum systems modeling and RDR's advanced structural and fault analysis module enabling an integrated approach to exploration to analysis Trap, Seal, Reservoir, & Charge in the same place. Building on the Ocean framework this release coincided with the release of the Ocean Store and online store where users can download plugins for Petrel. External links  http://www.slb.com/petrel  http://www.ocean.slb.com

ECLIPSE (reservoir simulator) ECLIPSE is an oil and gas reservoir simulator originally developed by ECL (Exploration Consultants Limited) and currently owned, developed, marketed and maintained by SIS (formerly known as GeoQuest), a division of Schlumberger. The name ECLIPSE originally was an acronym for "ECL´s Implicit Program for Simulation Engineering". ECLIPSE uses the finite volume method to solve material and energy balance equations modeling a subsurface petroleum reservoir. Versions include:  ECLIPSE 100 solves the black oil equations (a fluid model) on corner-point grids.  ECLIPSE 300 solves the reservoir flow equations for compositional hydrocarbon descriptions and thermal simulation  Intersect, a next generation reservoir simulator developed in partnership with Chevron.

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