Tubing string size is first selected and determined, and then the production casing size is selected and determined. After that the casing program is calculated. Thus the necessary conditions for scientific field development are provided. Contents of well completion engineering a. Core analysis and sensitivity analysis Core analysis and sensitivity analysis are systematically carried out on the core samples of exploratory and appraisal wells.
The terms of core analysis and sensitivity analysis are as follows. Drilling-in fluid selection For selection of drilling fluid, preventing formation damage caused by the invasion of filtrate and solids into formation should be considered, and safety problems during drilling of high-pressure, low-pressure, lost circulation, halite, halite gypsum, and fractured formations should also be considered.
The type, formula, and additives of drilling fluid should be designed on the basis of well log data, core analysis, sensitivity analysis data, and empirical practice. Well completion mode and method selection The well completion modes should be selected in accordance with field geology characteristics, field development practices, and types of wells of different rock formations such as sandstone, carbonatite, igneous rock, and metamorphic rock. The well completion modes are basically divided into two categories, openhole completion and perforated completion.
The openhole completion mode has several different methods such as open hole, slotted liner, and wire-wrapped screen gravel pack, while the perforated completion mode includes casing perforation, liner including casing tie-back perforation, and inside casing wire-wrapped screen gravel pack. Selection of tubing and production casing sizes The nodal analysis or pressure system analysis is used for reservoir—wellbore— surface pipeline sensitivity analysis.
The tubing sensitivity analysis is based on the composite analysis of reservoir pressure, production rate, liquid production rate, fluid viscosity, stimulation method, and development practices. The tubing size is selected first, and then the production casing size is designed on the basis of the tubing size. Formerly, it was necessary to choose the production casing size before selecting the tubing size. Advanced well completion engineering disregards this outdated method and has developed a system in which production casing size is determined on the basis of the tubing size.
The casing system design was originally composed of surface casing, intermediate casing, and production casing. Here we focus on the design of production casing rather than the other two, which have a special design that should match the requirements of drilling engineering. Production casing design The fundamental production casing design data, including category of well, type of well, well depth, physical properties of reservoir, fluid properties, in-situ stress, and engineering measures are listed as follows.
On the basis of the well completion method determined and the aforementioned influence factors, the casing steel grade, strength, wall thickness, types of thread and thread sealer, make-up torque, and so on are selected. For liner completion, the hanging depth and fashion should be designed.
For a steam injection well, the tension borne by casing thread and the sealing property of thread under thermal conditions should be considered, and the well should be completed under prestress. For directional and horizontal wells, the problems of casing bending, tension borne by casing thread, and casing thread sealing property should also be considered. Cementing design One-step, staged, or outside casing packer cementing and its cement slurry formulation are selected in accordance with the following conditions: 1 The requirements of different types of wells such as oil well, gas well, water injection well, gas injection well, and steam injection well for properties and return height of cement slurry.
Cementing quality evaluation Here, the cementing quality evaluation refers to inspecting the cementing sealing condition outside the casing, finding the channel and mixed mud-slurry segment, and determining the cement slurry return height.
At present, acoustic amplitude logging is commonly used for detecting the first sealing interface. The ultrasonic logging tool UCT-1 developed by the Jianghan Log Institute is a good cement job quality assessment instrument due to high penetrance of ultrasonic wave with high sensitivity to the change of propagation medium. The acoustic variable density log, which detects the second sealing surface of displacement, has not widely been used. Perforating and completion fluid selection The perforation density, perforation diameter, and phase are designed on the basis of perforating sensitivity analysis.
The perforator is selected according to reservoir permeability, oil property, and formation damage. The perforating methods, including cable perforating, tubing conveyed perforating TCP , modular perforating, and underbalance perforating, are determined by the reservoir pressure, reservoir permeability, and oil and gas properties. In the meantime, the perforating and completion fluids should be designed to match the reservoir clay minerals and reservoir fluid.
By analyzing skin factor, the causes of formation damage can be found in order to remove or reduce the damage. Well completion tubing string The production tubing string in gas and oil wells and special tubing string developed in China can be divided into the following types: 1 Permanent tubing string The permanent packer is set on the top of the reservoir before putting the well into production.
Each functional tool can be inserted into the mandrel below the packer, such as tools for separate zone injection, separate zone production, and separate zone testing. This tubing string can be used for sand washing, injecting cement plugs, and carrying out small-scale acidizing operations. The well can be converted into gas lift production if the flowing production rate decreases. However, this string is only adopted when the flowing period before gas lift is short because the gas lift valve is easily corroded during long idle times in the well and it has malfunctioned by the time of use.
The paraffin controlling, anti-scale, and salt deposit—resisting tubing strings are the same as the anti-corrosion tubing string, but the paraffin controlling, anti-scale, or salt deposit—resisting chemicals are injected. All of the preceding types of tubing strings should have circulation passage between the tubing and annulus. In addition, offshore wells, deep wells, ultra-deep wells, natural gas wells, highproductivity wells, and wells in special geographic environments such as flood discharge and earthquake regions must be installed with downhole safety valve at about — m below the wellhead m below the sea level for offshore well in order to avoid blowout.
Wellhead assembly The wellhead assembly is a main restrictor at the surface for the oil and gas flow from downhole. It is used for opening or shutting the well and controlling the direction and rate of oil and gas flow from downhole. In addition, it should be able to bear high pressure and resist corrosion, and ensure safety.
This is more important for oil wells with high pressure and productivity and especially gas wells with high pressure and productivity or H2S-containing natural gas well , for which the packaged cast-steel wellhead assembly is inappropriate and the integral forged block wellhead assembly should be used.
Measures for putting a well into production Different measures should be taken in accordance with the degree of formation damage and the type of oil and gas reservoir. The measures usually include swabbing, gas lift N2 , gassy water, and foam to aid flowing back, and sometimes hydrochloric acid or mud acid soak or high-energy gas fracture is used for plugging removal if necessary. In some wells, the acidizing and hydraulic fracturing must be taken before putting into production. Although well completion engineering combines drilling engineering and production engineering and remains a relatively independent domain, this engineering engineering system is not a work system but an inherent connection among drilling, well completion, and production engineering that considers the current and future macroscopic condition of the oil field development.
Well completion engineering is incapable of replacing drilling and production engineering; drilling, well completion, and production engineering must each do its own work well. In this era of advanced technology, they are mutually infiltrated, and all achieve a common progress.
Design procedure for well completion engineering The system design procedure of well completion engineering is as follows. Field development program Oil production test Core analysis Sensitivity analysis Nodal analysis Conventional analysis Slice analysis X. The basis of well completion engineering is a theory composed of the parts in reservoir geology, reservoir engineering, and petroleum production engineering, which are related to well completion.
The parts in reservoir geology and reservoir engineering include types, configuration, lithology, fluid properties, pore configuration, and fluid flow Completion Engineering Design Fracture Configurations Generated by Hydraulic Fracturing and Acid Fracturing Depend on in Situ Stress State 1. In the light of development geology, an oil and gas reservoir has its geometric configuration and boundary conditions, storage and flow characteristics, and fluid properties.
In accordance with different storage spaces and main flow channels of formation TABLE Basis of Well Completion Engineering 3 fluids, oil and gas reservoirs can be divided into the following types, shown in Table Porous reservoir. The storage space and percolation channels are the intergranular pores. Therefore, the flow is called flow in porous media such as sandstone, conglomerate, bioclastic limestone, and oolitic limestone reservoirs. Fractured reservoir. Natural fractures are not only the main storage space, but also the flow channels.
There may be no primary pores or be disconnected pores. Tight carbonatite and metamorphic rock reservoirs, and mud shale gas reservoirs, are of this type of reservoir. Fracture porosity reservoir. Intergranular pores are the main storage space, whereas fractures are the main flow channels. The flow is called flow in dual-porosity single-permeability media. Usually, the fractures extend for a long distance, but the pore permeability is very low. The Renqiu carbonatite oil field of China and the Spraberry Trend oil field of the United States are of this type of reservoir.
Porous fractured reservoir. Both intergranular pores and fractures are the storage space and the flow channels. The flow is called flow in dual-porosity dual-permeability media. Fractures grow fine, but extend for a short distance. The matrix porosity is low. The effective radius is defined as shown in Equation In general, using the S value is sufficient for evaluating whether a well has formation damage.
In general well test reports, the S value is only provided for indicating the degree of damage. However, the other parameters mentioned earlier can also be applied in order to analyze formation damage from different aspects Table The formation damage evaluation criteria of homogeneous and fractured reservoirs are shown in Table The evaluation criteria of the degree of damage of homogeneous reservoir and fractured reservoir are shown in Table In the s, Horner found that the radial flow in a reservoir corresponds to the linear portion on a semilogarithmic data plot, and he presented the idea that this linear portion can be used for obtaining the value of reservoir permeability.
This is a good application of graphic analysis. The bilogarithmic type curve match method was presented by Agarwal et al.
The downdip amplitude Ps value of the afterflow portion from the straight-line portion is dependent on the S value and is directly proportional to S. Two Radial Flow Portions. Conditions of appearance and typical combination of parameters are as follows.
Dual porosity reservoir and interporosity pseudosteady flow with the effects of wellbore storage coefficient C and skin factor S; 2. A composite bilogarithmic plot that meets the aforementioned conditions can be divided into the following flow portions Figure : 1. Curve shape is determined by CDe2S f. The derivative curve in this portion is a horizontal line with a derivative value of 0.
The derivative curve is concave downward and then rises to the horizontal line with a derivative value of 0. The dropping and rising of the curve are respectively dependent on lCD lCD and.
A semilogarithmic plot that meets the aforementioned conditions is shown in Figure However, although the existence of this type curve has been theoretically proved, no case has been collected in the field so far. This is the most common typical condition in oil and gas fields.
Conditions of appearance and typical parameters are as follows. Interporosity pseudosteady flow with the effects of C and S. A composite bilogarithmic plot that meets the aforementioned conditions is shown in Figure Figure is the corresponding semilogarithmic plot. The former a-b portion is mainly affected FIGURE Bilogarithmic plot with two radial flow portions under the condition of dual porosity reservoir. FIGURE Bilogarithmic mode chart having only the radial flow portion of total system under the condition of double porosity reservoir.
The b-c portion of the derivative curve is concaved downward and lower than 0. It is different from that of a homogeneous reservoir in that the b0 point is above the extended line of radial-flow straight-line portion c0 -d0.
Well test conditions: Sinian dolomite reservoir, m well depth, Well test results see Figure : The graphic characteristics coincide with that of the mode chart Figure FIGURE Semilogarithmic mode chart having only the radial flow portion of total system under the condition of double porosity reservoir. Well test conditions: Carboniferous dolomite reservoir, m well depth, Pressure was measured by using a mechanical pressure gauge under the condition of wellhead shut-in and opening.
Well test results see Figure : The curves measured are basically similar to those in the mode chart Figure A clearer radial flow portion of the total system may be measured if the testing time is further prolonged.
Case 3 1. Bottomhole shut-in was adopted for drillstem testing during drilling, which may only have a slight effect of afterflow. In addition, under the condition of double porosity reservoir, a method of estimating the value of o by using the bilogarithmic plot is shown in Equation This is coincident with the interpretation results of well test software.
Graphic Characteristics of a Reservoir with Hydraulically Created Fracture A reservoir with a hydraulically created fracture is also known as an artificially fractured reservoir and has a reservoir model that is completely FIGURE Composite bilogarithmic plot of Case 2.
The hydraulically created fracture is a single large fracture formed during hydraulic fracturing and has a high flow conductivity Figure Hydraulic fracturing can be adopted under the condition of homogeneous reservoir such as tight sand or double porosity reservoir such as dolomite with natural fracture , and a single fracture may often be formed because the highpressure fluid injected will first move forward in the direction with higher in situ stress; that is, the fracture face is always perpendicular to the direction with lower in situ stress.
After having been generated, the fracture may be continuously extended in the initial cracking direction. Under the condition of shallow reservoir, a horizontal fracture may be formed due to a low overburden pressure, while under the condition of FIGURE Hydraulically created fracture shape. A homogeneous reservoir cannot be changed to a double porosity reservoir by fracturing. However, in a double porosity reservoir, a large fracture may be formed by fracturing, thus losing the original double-porosity characteristics of a pressure build-up curve.
Such a well, which intersects a single large fracture, has been studied since , and more than 40 types of theoretical models have been created so far. These models can be divided into the following categories: 1. Vertical fracture with infinite flow conductivity, which is formed by hydraulic fracturing 2.
Vertical uniform-flux fracture 3. Vertical fracture with finite flow conductivity, which is formed by sand fracturing 4. Horizontal fracture formed in shallow reservoir during fracturing In addition, an early-stage afterflow portion may be formed due to the effect of wellbore storage under the aforementioned condition. The mode chart under vertical fracture with infinite flow conductivity is similar to that under vertical uniform-flux fracture except that the time when the linear flow appears is different.
The curve shape is similar to that of a homogeneous reservoir. The dimensionless wellbore storage coefficient is shown in Equation The ordinate distance between the two lines is 0. In this portion, the dimensionless pressure is shown in Equation The upper limits of tDXf under infinite flow conductivity and uniform flux are respectively equal to or less than 0.
In this portion, the dimensionless pressure derivative is shown in Equation The abscissa interval is about 0. The pressure derivative curve is a horizontal line, and the value of the dimensionless pressure derivative is equal to 0. CHAPTER 7 Well Completion Formation Damage Evaluation In the semilogarithmic plot, the curve mentioned earlier is continuously bent upward Figure , and the a0 -b0 , b0 -c0 , c0 -d0 , and d0 -e0 portions correspond to the relevant portions in the bilogarithmic plot.
Case 4 1. Well test conditions: Triassic sandstone reservoir, m reservoir depth, After producing for 40 days, the pressure build-up curve was measured at the bottomhole by using an electronic pressure gauge under the condition of wellhead shut-in.
Hydraulic fracturing had been taken before well testing. Well test results see Figure : The graphic characteristics are similar to those of the mode chart Figure Initially, there is an afterflow portion, which is similar to that of a homogeneous reservoir. The ratio of the distance between the two lines to the ordinate logarithmic period length is approximately 0.
Such a long portion indicates a long fracture. There is no radial flow portion measured. A semilogarithmic plot cannot be used for calculating reservoir parameters. It is indicated that a good obvious result of hydraulic fracturing has been obtained.
A large fracture with a length of m has been formed, thus fully improving the flow condition of the reservoir. If the curves are measured before and after the stimulation, the results can be concretely evaluated.
The flow conductivity of fracture may be a flow conductivity that is comparable to the permeability of the reservoir when a certain particle size distribution of proppant is achieved. There are slightly different definitions of flow conductivity.
Flow conductivity is defined by Agarwal as follows. FIGURE Semilogarithmic pressure plot of homogeneous reservoir under vertical fractures with infinite flow conductivity and uniform flux.
Different FCD values have different pressure curve shapes. The curve shape is similar to that under a low CDe2S value of homogeneous reservoir. The flow along the fracture is a linear transient flow. The representative formula is shown in Equation After deriving and taking the logarithm, Equation can be as shown in Equation The difference between Equations and is 0.
The derivative curve is a horizontal line. The dimensionless ordinate value is 0. The semilogarithmic mode chart is shown in Figure The flow portions shown in Figure correspond to those in Figure The curve is continuously bent upward and has no obvious characteristic except the e0 -f0 pseudoradial-flow straight portion. Case 5 1. Well test conditions: Triassic sandstone reservoir, m reservoir depth, 4. Hydraulic fracturing with 8 m3 proppant was adopted after perforating. After producing for 21 days, the pressure build-up curve was measured at the bottomhole by using an electronic pressure gauge under the condition of wellhead shut-in.
Well test results see Figure : The measured curves are similar to those in Figure and match the theoretical model well. It is known that the stimulation has a good obvious result. The pressure data had not been taken before stimulation. Fracture Skin Factor and Its Effect 1. Mechanism of fracture skin zone damage caused by fracturing During fracturing operations particularly massive fracturing , several hundred cubic FIGURE Semilogarithmic pressure plot under vertical fracture with finite flow conductivity and low FCD.
While cracking the reservoir and generating a large fracture, fracturing fluid may enter the fracture, and formation contaminant and damage may be caused Figure Fracture skin factor is defined as shown in Equation Equation indicates that the Sf value is mainly affected by the skin zone permeability KS and the skin zone thickness bS. The more serious the blockage, the lower the KS value. Effect of fracture skin on curve shape The fracture skin damage may undoubtedly increase resistance to flow and produce pressure drawdown, thus reducing gas well productivity.
Despite the fact that the fracture generated by hydraulic fracturing makes the flow at the bottomhole easy and smooth, the total skin effect may be increased due to the existence of fracture skin.
The early-time portion of the pressure derivative curve is concave downward due to the increase of the Sf value, which shows a graphic characteristic different from that of the curve without damage by skin Figure This is the most obvious characteristic of the existence of fracture skin. Case 6. Figure shows the measured pressure build-up curve of the S well in the Changbei gas field. The well of the Permian Sanxi-formation 0. The parameter values obtained by well test software analysis include: 1.
Case 7. Figure shows the measured pressure build-up curve of the Y well in the Changbei gas field. The well of the Permian Sanxiformation sandstone reservoir was hydraulically fractured during well completion.
The parameter values obtained by interpretation include: 1. Discussion 1. It is also considered that there is a further early fracture linearflow portion when the reservoir linear-flow portion has not been presented before the bilinear flow portion under the condition of fracture with finite flow conductivity.
Thus under the condition of fracture with finite flow conductivity, there are several flow portions, which include: earlier fracture linearflow portion, early bilinear-flow portion, reservoir linear-flow portion, pseudoradial flow portion, and sometimes the possible afterflow portion and late-time boundary response portion. However, in practice, to measure so many flow portions is difficult; one should use a high-precision electronic pressure gauge and should continuously observe for a long time, which may be several months or years.
It is of no practical significance for studying a reservoir and understanding well production. Uniform-flow fracture, if any, may only be formed by penetrating that original natural fracture after stimulation and may not be met often. It is theoretically considered that a horizontal fracture may appear in a shallow well, but typical measured data have not been obtained.
A long fracture that is connected with the wellbore is formed, thus changing the flow regime. It is necessary to understand the reason for causing low well productivity before designing stimulation in order to make a correct stimulation policy. Pressure build-up curves can be used for obtaining the values of reservoir permeability K and formation damage skin factor S, thus judging the reason for causing low well productivity. There are three circumstances that may follow after stimulation is taken: 1.
The degree of formation damage is decreased in the vicinity of the wellbore and the value of S is decreased. Not only is the degree of formation damage decreased in the near-wellbore area, but the reservoir permeability is also increased. After formation damage is removed or partially removed, the value of S is decreased to zero under the condition of homogeneous reservoir, or the value of S is decreased to some extent.
The changes of curve shape are as follows. In a bilogarithmic composite graph, the pressure derivative peak height H is reduced. The opening span A between pressure curve and pressure derivative curve at the radial flow portion in a bilogarithmic plot is decreased. Figure shows that the values of H and A are decreased to some extent.
The value of A is decreased from 1. The values of other parameters are unchanged. Case 8. A gas well has a depth of m. The Ordovician mud-siltstone dolomite reservoir has a thickness of 6 m and has net microfractures. The daily gas production rate was 1. After acidizing, the gas production rate was increased to 8. This well is important to the evaluation of this area. The comparison between the bilogarithmic curves before and after acidizing is shown in Figure The comparison between the semilogarithmic curves before and after acidizing is shown in Figure An obvious acidizing effectiveness can be qualitatively determined by Figure and Figure The specific change of S, however, should be determined by quantitative interpretation using well test software.
Table shows the interpretation results. The well was seriously damaged before acidizing, whereas the damage was fully removed and good effectiveness was obtained by using acidizing. The gas production rate was obviously increased.
S has no room for improvement. The C value was low before acidizing because the DST tool was used for testing, while the C value after acidizing was high because the test was performed under the condition of wellhead shut-in and opening.
Change of Curve Shape after Acidizing, Which Improves Both Skin Factor and Permeability In general, acidizing can only reduce the degree of formation damage in the vicinity of the wellbore rather than the whole reservoir. The acid volume injected during acidizing is limited.
Hydraulic fracturing can only create a single fracture with a limited length but can increase the nearwellbore reservoir permeability and improve the flow regime to some extent. Some low-permeability sandstone reservoirs will have an S value decreased and a K value increased after a fracturing operation. Figure indicates that the decrease of S value makes the values of H and A decrease and the increase of K value leads to a curve moving toward the left and losing the early-time portion.
Figure clearly indicates that the curve from afterflow portion to radial flow portion moves toward the left due to the increase of the K value.
Case 9. A well is located above a Mesoproterozoic buried hill and has a depth of m and a limestone reservoir thickness of 45 m. The core observation indicates that fractures are well developed. Thus a massive acidizing was taken. The increase of production rate was obvious.
The test curve is shown in Figure It is shown that the curve is obviously moved downward and the additional differential pressure ps, formed by formation damage in the nearwellbore area, has disappeared. It is shown that the S value is obviously decreased after acidizing and the damage is removed to a certain degree. Change of Curve Shape after Hydraulic Fracturing by Which a Large Fracture Is Formed When a long fracture is formed during hydraulic fracturing, the well test curve shape may be greatly changed.
The longer the fracture, the longer the duration of linear- or bilinear-flow straight-line portion. The mode charts are shown in Figure and Figure Case A gas well of the Sinian dolomite reservoir has a depth of m. During acidizing, which had an action of fracturing, the pump pressure was 30 MPa and the bottomhole pressure was about 60 MPa.
The acid volume of The gas production rate before FIGURE The curves which have characteristics of homogeneous or dual porosity reservoir before fracturing. The bilogarithmic curves before and after acidizing are shown, respectively, in Figure and Figure The curves in Figure are similar to that in the mode chart, and this method is appropriate to on-site evaluation of stimulation effectiveness. At present, well test interpretation software has been commonly used and quantitative calculation is almost no longer done by manual methods.
Well test interpretation software not only can be used for parameter calculation, but it can also be used for checking in order to ensure the reliability of interpretation results.
Manual methods cannot be used for checking, and no appropriate type curves can be constantly obtained by the manual method to ensure matching accuracy. The bilogarithmic type curve match method of calculating reservoir parameters is a quantitative well test interpretation method developed recently. Its principles are as follows.
Various types of oil and gas reservoirs are simplified into well test interpretation models, which include basic homogeneous, double porosity, and multilayer models with various inner and outer boundary conditions, including also the inner boundary conditions, which consider the formation damage in the vicinity of the wellbore that is, the S value and the wellbore storage coefficient C, and so on. The aforementioned well test interpretation models are expressed by mathematical equation, in which pressure p is the unknown variable, time t is the independent variable, and the various parameters such as production rate q, permeability K, skin factor S, wellbore storage coefficient C, fluid viscosity m, volume factor B, compressibility Ct, reservoir thickness h, and also o, l, Lb, Xt, and Re, are cross-variables.
The equation is generally expressed in a dimensionless form. For a homogeneous reservoir, under the conditions of the wellbore storage coefficient C and skin factor S on the inner boundary and the constant pressure on the infinite outer boundary, the mathematical model is as follows.
The equations are solved by using analytic or numerical methods, the pressure p is expressed as the function of time t and various crossvariables, and then the relational curves are drawn on log-log paper and known as type curves.
Different reservoir models have different type curves. The data of measured p related to t are drawn on the log-log paper with the same scales of ordinates, as shown in Figure , which is generally drawn on cellophane paper in order to be convenient for matching later. Figure is overlaid with Figure If the type curve model is suitable for the reservoir, some type curve may match the measured data points.
The traditional mode of well completion engineering, which had. Get Books now! Presents key concepts and terminology for a multidisciplinary range of topics in petroleum engineering Places oil and gas production in the global energy context Introduces all of the key concepts that are needed to understand oil and gas production from exploration through abandonment Reviews fundamental terminology and concepts from geology,.
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The have to be designed for safely maximising the hydrocarbon recovery from the well and may have to last for many years under ever changing conditions. Issues include: connection. The petroleum industry in general has been dominated by engineers and production specialists. Usually, neither of those disciplines have a great deal of training in the chemistry aspects of drilling and completing a well prior to its going. This book provides technical information on well completion, from drilling in the pay zone to production start-up.
It also covers the main methods for artificial lift, and well servicing. The reader will find a discussion of the concepts and equipment that are indispensable for scheduling and designing completion and servicing. While the public is generally aware of the use of hydraulic fracturing for unconventional resource development onshore, it is less familiar with the well completion and stimulation technologies used in offshore operations, including hydraulic fracturing, gravel packs, "fracpacks," and acid stimulation.
Issues include: connection. The petroleum industry in general has been dominated by engineers and production specialists. Usually, neither of those disciplines have a great deal of training in the chemistry aspects of drilling and completing a well prior to its going.
This book provides technical information on well completion, from drilling in the pay zone to production start-up. It also covers the main methods for artificial lift, and well servicing. The reader will find a discussion of the concepts and equipment that are indispensable for scheduling and designing completion and servicing.
While the public is generally aware of the use of hydraulic fracturing for unconventional resource development onshore, it is less familiar with the well completion and stimulation technologies used in offshore operations, including hydraulic fracturing, gravel packs, "fracpacks," and acid stimulation.
Just as onshore technologies have improved, these well completion. Well Control for Completions and Interventions explores the standards that ensure safe and efficient production flow, well integrity and well control for oil rigs, focusing on the post-Macondo environment where tighter regulations and new standards are in place worldwide.
Too many training facilities currently focus only on the drilling side. Once thought of as niche technology, operators today are utilizing more opportunities with casing and liners as formations and environments grow in difficulty, especially with the unconventional oil and gas boom. Casing and liners for Drilling and Completions, 2nd Edition provides the engineer and well designer with up-to-date information on. The book clearly explains the concepts of the drilling engineering and presents the existing knowledge ranging from the history of drilling technology to well completion.
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