The meaning of clay minerals, polymer and filtrate in the pores of the rock shall be emphasised here, since they can influence the formation damage decisively. Author used simulation machine at German Petroleum Institute (ITE) to simulate the borehole conditions. The varying permeability values of the used sandstones can be attributed to the fact that the corresponding different circulation fluids and different borehole conditions. The damaged cores examined by measuring the sectional damage of the cores and deep look inside the cores using the principle of scanning electron microscopy. Scanning of the surface of the specimen in the specimen chamber through a primary electron beam with a deflector. The back-scatter and secondary electrons are recorded and lead to a visualisation of the specimen surface, which is projected to a screen with the help of a video intensifier. The scanning of the specimen surface takes place under vacuum, so that the electron beam will not be scattered by air molecules.

Textprobe: Prior to any corrective action, an evaluation of damage and inflow performance should be carried out Production logs can provide excellent information about the productivity of the various intervals which should be providing production. Questions which can be addressed by production logs are: a) mechanical conditions of the well, i.e., casing, tubing or packer leaks, internal or external corrosion, b) anomalous fluid movement between zones, i.e., flow behind casing due to poor primary cementing, crossflow inside casing, c) completion efficiency evaluation of producing wells, i.e., are all zones producing, are some zones producing only gas or water, are the zones producing up to their potential indicated by other data sources?, d) completion efficiency evaluation of injection wells, i.e., how much fluid is going into various zones?, e) design and evaluation of stimulation treatments, i.e., which zones need stimulating, which zones responded to stimulation?, f) reservoir management, i.e., what are initial fluid saturations in each zone, what fluid saturation changes have occurred since initial completion, is the reservoir being depleted in the desired manner?. To add confidence to downhole analysis usually more than one logging device or measurement is required. The types of measurements which can be made downhole are: Temperature, which is a very basic measurement but can provide valuable information about fluid movement downhole, both inside and outside the casing. Temperature inside the tubing or casing is a result of heat flow and for fluid expansion. Heat is transferred through materials and liquids by conduction influenced by temperature difference. Heat is also transferred by convection due to fluid movement influenced by flow rate, temperature differences and fluid type. Temperature surveys following injection of fluids for water must be reasonably low. Also, fluid saturations in the rock near the wellbore may not be the same as those further away. Pulsed neutron bombardment of elements such as carbon, oxygen, chlorine, silicon, hydrogen, calcium, sulphur and iron in the rock near the wellbore permits the measurement of the relative saturation of the fluids with which they are associated. Many factors enter info calculation of fluid saturation by pulsed neutron techniques thus, these devices are most effective when used to compare changes in fluid saturation over a relatively long period of time due to production or a short period of time due to injection. Audible noise level and frequency patterns in the wellbore caused by movement of fluids inside or outside the casing can be used to establish the presence of flow, the path of flow, what phases are involved and to a degree, the flow rate. Sound transmission characteristics from a wellbore transmitter to a nearby receiver provide information as to acoustic coupling between the cement and the casing and the cement and the formation. Under favourable conditions these characteristics may be related to the possibility of fluid movement between zones outside the casing, electrical properties (i e, conductivity or dielectric constant) usually differ significantly between hydrocarbons and water. Thus, they may be used to determine relative amounts of these fluids at a particular level in the wellbore. These measurements are more definitive at low water percentages and where the fluids are intimately mixed again, the relative amounts of fluids residing at a particular level are not necessarily the same as the relative amounts of the fluids passing that level. An excellent measure of a well performance is through well testing. Oil and gas well production tests are generally classified as a) periodic production tests, b) productivity or deliverability tests and c) transient pressure tests. Periodic production tests are run to physically measure oil, gas and water produced by a particular well under normal producing conditions. Test results may be used to allocate total field or Specific PI accounts for the length of the producing section as follows: Eq. 11 Where: PI = Productivity Index /Length of Producing Zone q = total liquids stb/d pi = shut-in bottomhole pressure, psi pwf = flowing bottomhole pressure, psi pi - pwf = pressure drawdown, psi When the well producing above the bubble point the PI may be constant over a wide range of pressure drawdown’s However, with the flow below bubble point, and gas occupying a portion of the pore system, PI falls off with increased drawdown. Productivity index also declines during the life of a well due to many factors, among which are changes in reservoir pressure, composition and properties of produced fluids, relative permeability change and flow restrictions or formation damage near the wellbore. Productivity index does, however, give us a useful index of well and wellbore conditions. As long as we recognize the limitations of this method of well evaluation it can give us a measure for comparison between wells. Inflow performance testing is an improvement over the PI approach since it, in essence, looks at PI´s at several production rates PI attempts to represent the inflow performance relation of a well as a straight line function, as shown in Figure 10 6-1, Well A. The true inflow performance relation or IPR usually declines at greater drawdown’s, as shown in through the surface equipment, as shown in Figure 11 6-4. Each of these nodes can result in a pressure drop which the reservoir pressure much work against to produce various relationships are available to determine these pressure drops for various fluids being produced. This nodal system analysis will help in determining which nodes are limiting production and help in separating the difference between true formation damage and pseudo-damage, i e., completion restrictions. Flow after flow testing has been used for many years for determination of gas well capability. Essentially a plot of flow rate versus squared drawdown pressure on log-log paper provides a straight line which can be extended to predict flow rate for any drawdown. Oil well deliverability can be represented in the same manner. The method is particularly used for reservoirs producing below bubble point. Oil rate is related to pressure drawdown empirically as following: Eq. 12 Where: J = productivity coefficient n = empirically determined exponent, 0.5 < n < 1.0 Figure 12 6-5 shows flow rate and bottomhole flowing pressure versus time for a properly run flow after flow test. A log - log plot of flow rate, q vs (p? - p,?) should define a straight line with slope l/n. This plot can then be used to predict flow rate for any possible drawdown pressure as shown in Figure 13 6-6. At least four rates should be taken and each rate should continue until the well reaches a stabilized flowing pressure condition. This requirement for many wells means that long testing periods are required which often limits the usefulness of the flow after flow method range and apparently provides results comparable to the original flow after flow procedure. Transient Pressure Tests are probably the best way to determine true damage around a wellbore. The basic of pressure transient analysis assumes that the only well completed in a reservoir is shut in until a completely stable situation is reached. If this well is then put on production and pressure is reduced in the wellbore, a wave of reduced pressure gradually moves outward into the reservoir establishing a pressure gradient or sink toward the wellbore. With continued fluid withdrawals from the wellbore, the pressure wave moves further outward. Each point passed by the wave experiences a continuing pressure decline. At a particular time, the maximum distance the wave has travelled is called the drainage radius of the well. When the wave front reaches a closed boundary, pressure at each point within the boundary continues to decline, but at a more rapid rate. If the wave bent encounters a boundary which supplies fluid at a rate sufficient to maintain a constant pressure at the boundary pressure at any point within the drainage radius will continue to decline but a slower rate. With either the closed boundary or the constant pressure boundary the pressure gradient toward the well tends to stabilize after a sufficient time. Pressure level at a particular point may continue to decline. For the constant pressure boundary, a steady state will be approached where both pressure gradient and pressure level do not change with time. For the closed boundary a pseudo steady state condition is reached where pressure gradient is constant but pressure declines linearly with time at each point within the drainage radius. Changes in production rate or production from other wells will cause additional pressure wave movements which affect pressure decline and pressure gradients at every point within the drainage radius of the first well. The basis for transient pressure analysis is the observation of these pressure changes and the fluid withdrawal or injection rates which caused them, along with mathematical descriptions of the flow process, involving formation damage. Evaluation of damage where: Eq. 13 ?p = pressure drop across skin, psi p = formation volume factor, reservoir bbl/stb p =viscosity, cp s = skin factor, dimensionless k = permeability, md h = height, ft The value of the skin factors can vary from about -5 for a successfully hydraulically fractured well to m for a completely plugged well. Negative values indicate stimulation and positive values indicate damage. One problem with the concept of skin effect is that the numerical value of the skin (S) does not directly show the degree of damage. Using the Homer plot, as shown in Figure 14 6-9, the skin factor can be calculated. Flow efficiency (or condition ratio) describes the wells actual flow capacity as a fraction of its capacity with no damage, as following: Eq. 14 Damage ratio is the inverse of flow efficiency. Skin factor, flow efficiency or damage ratio can be determined from most transient pressure techniques. Wells completed with only a part of the producing zone open because of ineffective perforating. This example is based upon the assumption that there is uniform fluid entry along the horizontal well length. Calculate the pressure drops in the skin zones in vertical and 1000 f long horizontal wells. The well tests show a skin factor of +1 for the vertical as well as the horizontal well. The following additional reservoir properties are given: h =25ft, kv=kh=l0md qh = 2500 bbl/d qv = l000 bbl/d oil formation factor =1.06 rb/stb viscosity=0.8 cp Using equations (3) 6 and (4) 7 the results show 479 psi pressure drop in the vertical well and 30 psi in the horizontal well.

• Formation Damage

• Identification of Skin Effect

• Experimental work to identifying the Formation damage

• Oil and Gas Reservoirs Formation Skin Effect

• Borehole Conditions and Skin Effect

• Treatment of

Dr.Eng. Dr. Manag. Muhammed Mazeel Al-Aboudi has worked for many years in the international sector of the oil and gas industry in several countries. He studied at the Faculty of Mining and Geology-Department of Petroleum engineering of the University of Belgrade (Diploma in Engineering), the Escuela Superior de Minas in Madrid, Spain (Credit in Applied Geophysics Engineering) and the University of Clausthal-Zellerfeld in Germany. He was awarded a PhD in Petroleum Engineering by the Technical University of Clausthal-Zellerfied in Germany. He was awarded another PhD in Management and Petroleum Economics by University of Bradford in United Kingdome. He started working as, Petroleum Engineer, Reservoir Engineer, Drilling, and Production Engineering, focusing on issues like Reservoir Engineering, Petroleum Engineering, Fiscal Regimes, Cost Estimation, Petroleum Economics, Strategic Planning, Portfolio Management, and Energy Policies. Dr Mazeel has been employed in many European companies as a Senior Petroleum – Reservoir Engineer He has also worked as Director General of the Iraqi Drilling Company (IDC) and Director General for the Oil Products Distribution Company (OPDC). At the same time, he was the oil industry adviser to the Iraqi Prime Minister in 2005-2006. Director General of Reservoirs and Fields Development Directorate (RFDD) at the Ministry of Oil in Iraq. He is the Author of many papers and books on petroleum engineering, fiscal regimes, management and marketing, energy policies for the Oil and Gas Journal, Middle East Economy Survey (MEES), Society of Petroleum Engineers (SPE), the Canadian Institute of Mining, Metallurgy and Petroleum (CIM), the German Oil-Gas Coal Magazine (EEZ), and Diplomica Verlag.