682 Reservoir Formation Damage Reservoir Type Classification Review of Processes Structural Settings LKhostratlgraphy Depositions! Env. Facies Analysis Petrophysics Petrographic Classification Heterogeneities Diagenetic Processes Clays Framework Char. Pore System Completion Methods Surface Facilities Operation Well Testing Previous Treatment History Diagenetic Minerals Practices Figure 22-1. Issues involving candidate selection and reservoir formation damage studies (after Yeager et al., ©1997 SPE; reprinted by permission of the Society of Petroleum Engineers). Task 2 Determination of Damage Pressure Transient Testing & Analysis Delfverabiltty Decline Analysis Downhole Diagnostic of Existing Damage Mechanisms RSCT Testing U.S. Patent No. 5,253,719 Baiter Samples Wellbore Fluid Samples Downhole Video Initial State Cora Analysis Natural Fluid Analysis Core Flow Testing On-SMe Injection System Damage Testing Treatment Fluid Flowback Diagnostics Rock Mechanics Geochemical Simulation Figure 22-2. Issues involving reservoir formation damage determination (after Yeager et al., ©1997 SPE; reprinted by permission of the Society of Petro- leum Engineers). Field Diagnosis and Measurement of Formation Damage 683 perforations. Figure 22-3 by Yeager et al. (1997) shows a schematic of a typical high-resolution video camera and a still image, indicating sig- nificant wellbore scaling, obtained using this camera. The video observa- tions also provide valuable information necessary for determination of the flow distribution that can be used to improve the accuracy of the well- test interpretation and identification of the formation damage mechanisms (Yeager et al., 1997). Pressure transient tests yield information on the permeability and formation thickness product, (Kh), and skin factor, s. As pointed out by Yeager et al. (1997), pressure transient tests only provide information at a specific time, when the tests are conducted. Therefore, formation damage can be more effectively evaluated by conducting a series of tests over a length of time and also the true skin should be determined after corrections for other effects, such as non-Darcy or inertial effects (Yeager et al., 1997). In openhole completed wells, core samples can be taken from the wells using a rotary sidewall coring tool (Yeager et al., 1997). The material on the face of the extracted cores should be carefully preserved during the transportation of the core for later analytical studies (Yeager et al., 1997). Flbar Optic Cabla Planing Neck Cabta H«»d Bow Spring* Canwra lUrrtl Assembly Camera Lam Light Dome Pmaaun Housing Bull Nose Plug Figure 22-3. Typical downhole video image and elements of a downhole video camera (after Yeager et al., ©1997 SPE; reprinted by permission of the Society of Petroleum Engineers). 684 Reservoir Formation Damage Pseudo-Damage Versus Formation Damage Amaefule et al. (1988) plainly stated that "Formation damage is an expensive headache to the oil and gas industry." A number of factors cause formation damage in a complicated manner. Amaefule et al. (1988) grouped these factors in two categories: 1. Alteration of formation properties by various processes, including permeability reduction, wettability alteration, lithology change, release of mineral particles, precipitation of reaction-by products, and organic and inorganic scales formation 2. Alteration of fluid properties by various processes, including viscos- ity alteration by emulsion block and effective mobility change The impact of formation damage can be observed in a variety of ways, including (1) abnormal decline in well productivity or injectivity, (2) mis- diagnosis of potential pay zones as nonproductive, and (3) delay of pay- out on investment (Amaefule et al., 1988). Hayatdavoudi (1999) points out that the analysis of production data is complicated because of: 1. Mechanical problems related to the tubing, safety valves, lift equipment, and wax, paraffin, and scale build-up in the tubing 2. Formation damage due to fines migration, development of skin, completion damage, and many other factors 3. Changes in reservoir conditions, like appearance of water-cut, changes in productivity index, and other related factors Among other factors, the productivity or injectivity of wells depend on the pressure losses that occur along the flow path of produced or injected fluids. As schematically depicted in Figure 22-4, pressure losses may occur at various locations along the well and in the reservoir formation. Therefore, Piot and Lietard (1987) expressed the total skin of a well as a sum of the pseudoskin of flow lines from the formation face to the pipeline and the true skin due to formation damage. Here, the focus is on the near-wellbore formation damage problem. Figure 22-5 schematically depicts the damaged region around a well. Measures of Formation Damage Formation damage can be quantified by various terms, including (1) damage ratio, (2) skin factor, (3) permeability reduction index, (4) flow efficiency, and (5) depth of damage. Field Diagnosis and Measurement of Formation Damage 685 Surface Choke Safety Valve Well Restriction Completion Near-Wellbore Damage Non-damaged Reservoir Formation Pseudo Damage (Total pressure loss) Actual Damage (Pressure loss by formation damage) Figure 22-4. Pressure losses during production. Skin Factor The skin factor is a dimensionless parameter relating the apparent (or effective) and actual wellbore radii according to the parameters of the damaged region: ( r \ = V w > apparent w ' actual (22-1) 686 Reservoir Formation Damage Non-damaged formation Damaged formation (Skin effect) Figure 22-5. Schematic of a damaged zone in the near-wellbore (modified after Ohen and Civan, 1989). where s is the skin factor. The skin factor is a lumped parameter incor- porating the integral affect of the extend and extent of damage in the near- wellbore region. Frequently, in reservoir analysis and well test interpre- tation, the skin factor concept is preferred for convenience and simplicity, and for practical reasons. Therefore, many efforts have been made to express the skin factor based on the analytical solutions of simplified models relating well flow rate to formation and fluid conditions. In this respect, incompressible one-dimensional flow in a homogeneous porous media formulation approach has been popular. Other cases, such as anisotropic elliptic and isotropic radial flow problems can be readily transformed into one-dimensional flow problems, using respectively (x-a K, (22-2) = lnr where K x , K y , and K z are the permeabilities in the x, y, and z-principal directions in an anisotropic porous media; a, b and c denote the coordin- ates of the well; and r and I denote the radial and linear distances in the flow direction. Field Diagnosis and Measurement of Formation Damage 687 The formation anisotropy ratio of permeability, |3, is defined following Muskat (1937): (22-3) Although this transformation distorts the wellbore shape from the cylin- drical shape (Mukherjee and Economides, 1991), it can still be used for all practical purposes with sufficient accuracy. Permeability Variation Index (PVI) The permeability variation index expresses the change of formation permeability by near-wellbore damage as a fraction, given by (22.4, where K and K d denote the formation permeabilities before and after damage, respectively. Viscosity Variation Index (VVI) The viscosity variation index expresses the change of fluid viscosity by various processes, such as emulsification, defined by: where (I and |i rf denote the fluid viscosities before and after fluid damage, respectively. Damage Ration (DR) The damage ratio expresses the change of well flow rate by near- wellbore damage as a fraction, given by (Amaefule et al., 1988): q q ^ > where q and q d denote the undamaged and damaged standard flow rates, respectively. 688 Reservoir Formation Damage The production loss by alteration of formation properties can be formulated as following. The theoretical undamaged and damaged flow rates for a steady- state incompressible radial flow in a homogeneous and isotropic porous media are given, respectively, by (Muskat, 1949; Amaefule et al., 1988): 2nKh(p e -p w ) \LBln(r e /r w ) (22-7) 2nKh( Pe - Pw ) (22-8) Therefore, substituting Eqs. 22-6 and 7, Eq. 22-8 yields the following expression for the damage ratio: DR = (K/K d -l)ln(r d /r w ) (22-9) where jo, and B are the fluid viscosity and formation volume factors. K and K d are the undamaged and damaged effective permeabilities, h is the thickness of the effective pay zone, p w and p e are the wellbore and reservoir drainage boundary fluid pressures, r w and r e are the wellbore and reservoir drainage radii, and r d is the radius of the damaged region. The effective skin factor, s, is defined by (Craft and Hawkins, 1959): = (K/K d -l)ln(r d /r w ) (22-10) Thus, substituting Eq. 22-10 into Eq. 22-9 yields the relationship between the damage ratio and the skin factor as: DR = (22-11) The economic impact of formation damage on reservoir productivity can be estimated in terms of the annual revenue loss by formation damage per well (FD$L) at a given price of oil, p, according to Amaefule et al. (1988): Field Diagnosis and Measurement of Formation Damage 689 year day bbl DR bbl unproduced | bbl theoretical } (22-12) Figure 22-6 by Amaefule et al. (1988) shows the typical curves of the damage ratio and annual revenue loss per well as a function of the damage radius and degree determined by Eqs. 22-8 and 12, respectively. Because the degree of damage varies in the near-wellbore region, it is more appropriate to express the total skin as a sum of the individual skins over consecutive segments of the formation as (Li et al., 1988; Lee and Kasap, 1998): (22-13) where N represents the number of segments considered (see Figure 22-7). The production loss by alteration of fluid properties can be formulated as following. Rapid flow of oil and water in the near-wellbore region promote mixing and emulsification. This causes a reduction in the hydro- carbon effective mobility, k(K = K e /\Ji = Kk r /\Ji) (Leontaritis, 1998), because emulsion viscosity is several fold greater than oil and water viscosities. High viscosity emulsion forms a stationary block which resists flow. It is called emulsion block. If (U, and [i d represent the viscosities of oil and emulsion, respectively, and a steady-state and incompressible radial flow is considered, the theoretical undamaged and damaged flow rates are given, respectively, by: _2nKh(p e -p w ) (22-14) 2nKh( Pe - Pw ) (22-15) Thus, substituting Eqs. 22-14 and 15 into Eq. 22-6 Leads to the following expression for the damage ratio: DR = [\l d B d /(\iB)-i\£n(r d /r w ) (22-16) o o 1.0 0.8 0.6 0.4 0.2 Well Spacing = 40 Acres Drainage Radius (r e ) = 660 Feet Well Bore Radius (r w ) = 0.25 Feet Undamaged Rate = 500 B/D Oil Price = $15/B - Legend Radius of Damage (r<j). FT X 0.26 O 0.50 -£ 1.0 . 4.0 Q 10.0 2.74 2.19 m 1.64 1.09 0.55 10' 3 10' 2 10 Ratio of Damaged to Undamaged Zone Permeability (Kd/K e ) Figure 22-6. Effect of permeability impairment and damaged zone radius on damage ratio (after Amaefule et al., ©1988; reprinted by permission of the Canadian Institute of Mining, Metallurgy and Petroleum). 90 CD C/3 n> o o a p Field Diagnosis and Measurement of Formation Damage 691 Figure 22-7. Near-wellbore damaged zone realized as a series of sectional damaged zones. Figure 22-8 by Amaefule et al. (1988) shows the effect of emulsion block on oil production rate according to Eq. 22-16. The viscous skin effect can be expressed similar to Zhu et al. (1999) as: *n = \LB (22-17) Flow Efficiency Flow efficiency is the ratio of the damaged to undamaged formation flow (production or injection) indices: FI (22-18) where p and p wf denote the average reservoir fluid and flowing well bottom hole pressures, respectively, and A/? x is the additional pressure loss by the skin effect. The flow efficiency of vertical wells for radial [...]... February 22- 23, 199 0, pp 185-200 Ohen, H A., & Civan, F., "Predicting Skin Effects Due to Formation Damage by Fines Migration," SPE 21675 paper, Proceedings of the 199 1 SPE Production Operations Symposium, Oklahoma City, Oklahoma, April 7 -9, 199 1, pp 39 9- 410 Ohen, H A., & Civan, F, "Simulation of Formation Damage in Petroleum Reservoirs," SPE Advanced Technology Series, Vol 1, No 1, April 19 93 , pp 27 -35 Olarewaju,... ( 199 9) shows the production data for Well No 2, for which the change in the phase angle and, therefore, the formation damage began at Month 33 , as indicated by Figure 22-15 by Hayatdavoudi ( 199 9) Notice the widening of the phase angle pattern 0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 Time (Month), (A"0- 197 8 - Dec 199 4) Figure 22-12 Well No 1 production data (after Hayatdavoudi, 199 9;... 192 204 Time (Month), ( Oct 197 8 - Dec 199 4) Figure 22-14 Well No 2 production data (after Hayatdavoudi, 199 9; reprinted by permission of A Hayatdavoudi) 702 Reservoir Formation Damage 0 12 24 36 48 80 72 84 06 108 120 132 144 156 168 180 182 204 Time (Month), (Oct 197 8 - Dec 199 4) Figure 22-15 Discrete Fourier transform phase diagnostic analysis of Well No 2 production data (after Hayatdavoudi, 199 9;... Performance," SPE Formation Evaluation, June 199 1, pp 2 09- 216 Muskat, M., The Flow of Homogeneous Fluids Through Porous Media, McGraw-Hill Book Co., New York, New York, 1 93 7 Muskat, M., Physical Principles of Oil Production, McGraw-Hill, Inc., New York, 194 9 Ohen, H A., & Civan, F, "Simulation of Formation Damage in Petroleum Reservoirs," SPE 194 20 paper, Proceedings of the 199 0 SPE Symposium on Formation Damage. .. continuity): (22 -31 ) (22 -32 ) The dimensionless variables and/or parameters are defined as following: (22 -33 ) (22 -34 ) tn = aKj (22 -35 ) (22 -36 ) (22 -37 ) _ 'i (22 -38 ) (22 - 39 ) 698 Reservoir Formation Damage In these equations, the indices 1 and 2 denote zones 1 and 2; rw, re, and r represent the wellbore and drainage radii and radial distance from the center of the well, respectively; t is time, B is the formation. .. Figure 22 -9 Steps of integrated near-wellbore formation damage analysis and prediction (after Ohen and Civan, © 199 1 SPE; reprinted by permission of the Society of Petroleum Engineers) 696 Reservoir Formation Damage Figure 22-10 Composite of damaged and non-damaged regions realization of a reservoir (after Olarewaju, © 199 0 John Wiley & Sons Limited; reproduced with permission) The dimensionless partial... Skin Factor As demonstrated by Ohen and Civan ( 199 1, 199 2, 19 93 ) , skin factor varies over time and can be predicted by means of a formation damage model Figure 22 -9 depicts the approach used by Ohen and Civan ( 199 2) for prediction of the skin factor associated with formation damage resulting from fines migration and clay swelling effects in the nearwellbore formation Model-Assisted Analysis of the Near-Wellbore... Wells," Proceedings of the 199 9 SPE Mid-Continent Operations Symposium held in Oklahoma City, Oklahoma, USA, March 28 -31 , 199 9 Chapter 23 Formation Damage Control and Remediation Summary Formation damage is an undesirable operational and economic problem that may occur during the various phases of oil and gas recovery from petroleum reservoirs Control and remediation of formation damage are among the most... "Asphaltene Near-Wellbore Formation Damage Modeling," SPE 39 446 paper, Proceedings of the 199 8 SPE Formation Damage Control Conference, February 18- 19, 199 8, Lafayette, Louisiana, pp 277-288 Li, Y-H., Fambrough, J D., & Montgomery, C T., "Mathematical Modeling of Secondary Precipitation from Sandstone Acidizing," SPE Journal, December 199 8, pp 39 3-401 Mukherjee, H., & Economides, M J., "A Parametric Comparison... Hayatdavoudi, 199 9; reprinted by permission of A Hayatdavoudi) Field Diagnosis and Measurement of Formation Damage 701 Post-Acidizing 24 96 48 60 72 64 96 108 120 132 144 156 188 180 182 204 Time (Month), (Aug 197 8 - Dec 1 094 ) Figure 22- 13 Discrete Fourier transform phase diagnostic analysis of Well No 1 production data (after Hayatdavoudi, 199 9; reprinted by permission of A Hayatdavoudi) 72 84 86 108 120 132 . continuity): (22 -31 ) (22 -32 ) The dimensionless variables and/or parameters are defined as following: tn = aKj _ 'i (22 -33 ) (22 -34 ) (22 -35 ) (22 -36 ) (22 -37 ) (22 -38 ) (22 - 39 ) 698 Reservoir Formation Damage In . Civan ( 199 1, 199 2, 19 93) , skin factor varies over time and can be predicted by means of a formation damage model. Figure 22 -9 depicts the approach used by Ohen and Civan ( 199 2) for . by Hayatdavoudi ( 199 9). Notice the widening of the phase angle pattern 0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204 Time (Month), (A"0- 197 8 - Dec. 199 4) Figure