Numerical Evaluation of Formation Damage Models for Application in Niger Delta Oil Reservoirs

The frequent random application of formation damage models in the assessment of oil well deliverability has prompted the critical evaluation of these models to streamline their applicability in specific reservoir types. Coupled with the unconsolidated nature of the Niger Delta Agbada formation, the establishment of a unique damage model which will take into account, the textural and structural configuration of the formation sand in its damage estimation is most paramount. In this work, four formation damage models were numerically evaluated and matched to the conventional pressure buildup skin model using reservoir and well production data from five (5) different Niger Delta locations assigned ND-1, ND-2, ND3, ND4 and ND-5. Result showed that the Frick & Economides model, if adopted within the region can be dreadful for all reservoir cases as it tends to underestimate formation damage implications as well as skin magnitudes since it is primarily a function of the altered permeability and damaged radius only, recording an average skin of 1.30 as against 3.36 for the reference model. The models of Behr & Raflee, Ozkan and Furui et al with reference to the buildup skin model showed promising results in skin magnitude estimation. Further damage analysis revealed that the Furui et al model was most appropriate as it yielded an average Flow Efficiency of 69.40%, an average skin induced pressure drop of 193.98 psi and an average damage factor of 0.3 Keywords— Evaluation, Formation, Model, Niger Delta,


INTRODUCTION
The Niger Delta, p roven to have an estimated reserve of about 37.2 b illion barrels of oil is branded as one of the major o il and gas province within the Gu lf of Gu inea. Averaging an estimated daily withdrawal of 1.6 million barrels of oil per day, though greatly attributed to quite a number of socio-economic and political reasons, a good percentage of this reduction in daily production within the province can also be ascribed to a wide range of factors. These factors may be natural o r incurred owing to high degree of uncertainties associated with oil and gas exploration. Uncertaint ies in petro-physical evaluation, reserve estimation, poor evaluation of target recovery mechanis ms peculiar to specific reservoirs and many mo re may retard production benchmarks. Characterized by an unconsolidated sandstone formation, the Niger Delta oil bearing rocks have been thought and proven to suffer some reservoir rock-related productivity problems. These problems span fro m sand production as a result of the unconsolidated nature of the res ervoir rocks to formation damage or permeability impairment, possibly as a result of fines migration and other sources.Format ion damage in plain terms refers to the reduction of the permeability o f the formation as a result of drilling, co mplet ion, production and injection operations. It is a peculiar problem in petroleu m reservoirs, occurring in d ifferent stages of reservoir development fro m drilling to production and fluid reinjection. Over the years, quite a number of drilling and production practices have recorded significant losses in millions of recoverable barrels of oil and billions of cubic feet of gas. This invariably imp lies that formation damage phenomenon is absolutely unnatural to the reservoir flo w channels within the wellbore vicin ity which may impair the productivity of hydrocarbons from that reservoir. It is convenient to say that all producing formations are depth filters, varying in shapes sizes and may contain constrictions where bridging of mig rated particles can restrict flo w. Also in highly react ive formations like shale with h igh percentage of clay mineral, heaving may contribute to formation damage when contacted with water mo lecules. The econo mic impo rtance of formation damage phenomenon has prompted the evaluation of numerous mitigation methods by several scholars, who seek by experimental and mathemat ical methods, preventive techniques to mitigate these occurrences. Traditionally, experimental studies in this regard have been for special case studies, peculiar to a part icular environment without conjoining mathemat ical correlations which will provide a research springboard for future investigators.
Despite the vast number of theoretical, experimental, and numerical studies on formation damage, a robust and comprehensively outstanding model capable of predicting the degree to wh ich formation damage occur, especially within regions of poorly sorted petroleum format ion such as the Niger Delta is paramount. The existence of such models is essential for successful development and design of damage mitigation processes. Most models have their validity based on experimentally obtained parameters fro m reservoir core samples under specific laboratory conditions. In this vain, their application is rather limited to field adaptations and as such, some sound level of model assumptions to adequately adopts these models to various reservoir types are requisite. This damage phenomenon occurs not primarily by drilling and completion operations alone, but also occurs as a result of several co mplicated reservoir processes. Damage intensity can also be traceable to the flowing fluid properties and the geological orientation of the porous med ia i.e., the rock-fluid interaction. On this ground it is imperative that formation damage modeling must incorporate flu id-rock co mpatibilities, precipitation reactions, particulate processes in pore throats, swelling in reactive format ions like clay, wettability, adsorption, absorption, net stress and compressive variations. According to He et al., 2002;Brandford et al., 2010, subsurface fluids often contain in them suspended particles that may affect both flow and mechanical properties of the resident formation with time. Drilling mud infiltrat ion into the near wellbore reg ion, migration of fines, propant from hydraulic fractures, and contaminants fro m underground water are all a means by which formation damage can be quantified in a porous media. In a b id to realize optimu m recovery in o il and gas investments, it essential that all maximu m well productivity techniques be explored. For this reason, identificat ion and evaluation of effective formation damage models is paramount. Formation damage can occur at any point in the life of a reservoir fro m drilling, co mplet ion, work-over operations, well interventions and total depletion of the reservoir. This formation damage may be as a result of scaling and fine migration. (Schaible, et al., 1986;. Formation damage in petroleu m reservoirs occurs as a consequence of the comb ined effects of several co mp licated processes. The extent of damage depends on the properties of the fluids and the geological configuration of the porous med ia, and the nature of fluid-flu id and rock-fluid interactions (Schaible, et al,. 1986). Therefo re, fo rmation damage modeling should account for flu id-fluid and rockflu id incompatib ilit ies, dissolution and precipitation reactions, pore deformation and collapse and sand production phenomena, particulate processes in porous structure, swelling of porous matrix and clay particles, effects of adsorption, (Civan, 2007;Ozkan and Raghavan, 1997;Mansoori, 1997). The effect of skin can considerably reduce the production performance of any reservoir, be it sandstones, carbonates or shale. The skin phenomenon occurs when migrated fines are accu mulated in and around the wellbore region as a result of production operations, drilling, workover, complet ion operations or even fluid inject ion operations. This phenomenon creates a distinction in the transmissibility of flu id in the reservoir, altering the permeability of the affected region. The 2-region reservoir model shown in Figure 1 is a convenient representation of a damaged wellbore region.
Here, the altered zone is assumed to be of a uniform permeab ility ks out to a radius rs, beyond which the formation permeability, k is unaltered. Using the 2-reg ion model, the skin magnitude can be mathematically deduced with the following equation The model when validated drew a previously developed concept of "wave-front movement" and "flow-biased probability" for linear systems using monodispersed and polydispersed suspensions. Results fro m their analysis showed that parameters so obtained from linear models were conventional when compared to results obtained fro m other radial models. He et al., (2013) developed a fluidsolid coupling fin ite element model to simu late and quantitatively analyze the pressure evolution in the reservoir as well as damage and permeability change in the formation during long-term water flooding process. Their obtained results provided a theoretical co mprehension of the benefits (pore pressure increase in the simulation domain), rock damage, permeab ility change of long -term water flooding, and offered an in-depth knowledge on how to detect and prevent wellbore failure and collapse due to formation damage during water flooding.
Regardless of the nu merous experimental studies on formation damage of oil and gas bearing format ions, only very few attempts to adequately mathematically model the process have been done. The application of these models in actual reservoir analysis and management has been rather limited because of the difficu lties in the understanding and implementation of these models. (Byrne and Rojas, 2013;. Organic deposition both in and around the wellbore is perhaps the most prominent form of damage problem reported in the mature oil-p roducing reservoirs world wide. These organic deposits fall into two broad categories, paraffins and asphaltenes. Paraffins and asphaltenes can deposit both in tubing and in the pores of the reservoir rock, significantly limiting well productivity (Petrowiki, 2015). The plugging of reservoir -rock pore throats can be caused by the fine solids found in mud filtrate or in solid particles dislodged by a filtrate within the rock matrix. In order to reduce this, it is often a common practice to encourage using nano sized solid particles in mud preparation when designing to counteract fluid losses (Zain, and Sharma, 2000). Bu ildup of fine part icles being transported, particularly in sandstone reservoirs, can significantly reduce well productivity due to the mobile nature of particles, particularly in unconsolidated system. Direct evidence of migrated fines-induced formation damage in production wells are usually difficult to be encountered (Aristov et al., 2015). While other mechanisms of formation damage have obvious indicators of the phenomenon, field indications of fines migration are much more elusive. Indirect evidence such as declining productivity over a period of several weeks or months is the most common symptom. This reduction in productivity can usually be reversed by mud-acid treat ments. A large number o f wells around the world fo llo w these patterns of reduction of productivity fo llo wed by significant improvements when subjected to a mud-acid treat ment. This behavior most often suggests a buildup of fines in the near-wellbore reg ion over a period o f t ime (Nguyen et al., 2013;Olivera et al., 2014). Field studies and laboratory experiments have indicated that the fines causing the permeab ility reduction include clays, feldspars, micas, and plagioclase. Because the mobile fines are made up of a wide variety of minerals, the clay content of the reservoir may not always be a good indicator of the water sensitivity of the format ion . Owing to the fact that reservoir rock property classification vary fro m p lace to place possibly as a result of several geological and stratigraphic configuration, it may be convenient to conclude that the adaptation of petro-physical properties of reservoir rocks for formation damage modeling should be exclusive to a part icular model that can accurately mimic the candidate reservoir system. Over the years, there have been quite a nu mber of formation damage reviews but none in recent time, pertinent to its applicability with in the Niger Delta fo rmations has yet been established. It is therefore important that that the establishment of suitable formation damage models v ia sound engineering evaluations be implemented, putting in to consideration, the petro-physical properties peculiar to the region. Several Mathematical models in conjunction laboratory evaluations have provided some degree of co mprehension into the spatial development and quantification of format ion damage. For examp le if suspended colloidal part icles /or formation grains carry electrostatic charges, particles might attach to the grains' surface and get entrapped. This phenomenon has classically been modeled by the \single collector model (Zamani and Maini, 2009). A variety of studies have been done to quantify formation damage and formulate it in terms of permeability impairment as a function of time and properties of flow, suspended particles, and porous media. Moreover, industrial standard measures pertinent to reservoirs are in place, many of which are only applicable under limited circu mstances. For examp le, a co mmon rule of thu mb is if part icles been are greater than 33% of the median pore throat diameter, they will form stable bridges which can cause permeability reduction. While this is only valid for turbulent flow, particles as small as 7% of the median pore throat size have the ability to plug the pores in laminar flow cases (Blyton et al., 2017). Th is, however, lack of a global criterion fo r particulate bridg ing imp lies that a thorough comprehension of the phenomenon of format ion damage entails a comprehensive study of all of the contributing factors and mechanisms  Fallah and Sheydai, (2013),revealed that, near wellbore mud the resulting formation damage considered one of most encountered problems involving the petroleu m reservoir exploitation. They assumed suspension concentration which was based on the fact that for each flow velocity there does exist the maximu m amount of retention particles that electric -molecu lar forces can keep. The dimensionless erosion number, wh ich is ratio between the cross flow drag force and the total of normal forces, is proportional to flo w velocity. The stabilizat ion phenomenon was characterized by so called storage capacity which is the maximu m retention concentration versus erosion number.  in an attempt to model for quantitative formation damage in oil the reservoir during microbial enhanced oil recovery shows that for a continuous microbial injection operation, the total pore area of the format ion decreases in an equivalent percentage via the microbial plugging and biomass accumulation mechanisms within the reservoir. The prevailing effects of format ion damage due to these microbes were also presented with residual flu id flow rates and corresponding velocities decreasing in magnitude fter several days of microbial in jection. The author presented a second order PDE wh ich was resolved using the Exp licit Fin ite Difference Appro ximation method. The model was to estimate the pore area reduction in the reservoir due to biomass accumulation.

II. MATERIALS AND METHODS
The fundamental principles upon which the formation damage (skin) models will be evaluated will include the damaged zone permeab ility assessment, analytical evaluation of formation permeability via well test analysis (particularly for pressure buildup transient test), flo w efficiency analysis, skin induced pressure models and damage intensity. Field parameters were collected form five reservoirs at different locations within the Niger Delta. The selection process was influenced by the research scope which as earlier stated, will consider and limit this analysis to oil reservoirs only within the reg ion. These parameters comprised of data obtained fro m four onshore operators and an offshore operator. With each field producing at a desired optimu m production constraint and with adequate sand control measures in p lace, sand production data was also obtained. The nomenclature assigned to each location is ND-1, ND-2, NG-3, ND-4 and ND-5, with ND-5 being the only offshore field amongst all five operators.

Damage (Skin) Models to be Evaluated 2.2.1. Frick and Economi des Model
In the estimation of equivalent skin factor, assuming both conically and cy lindrically shaped damaged zone and putting into consideration the net pay thickness of the reservoir pay interval, the magnitude of formation damage will be estimated using that presented by Yildiz, (2008) Dimensionless skin factor at damaged radius x k is the average undamaged reservoir permeability, mD kd is thedamaged reservoir permeability, mD Iani is the anisotropic index, Dimensionless rd(x) is the damaged radius, (ft) rw is the wellbore radius (ft) kH is the horizontal permeability of the reservoir, mD kV is the vertical permeability of the reservoir, mD Accounting for the effect of formation damage on well productivity, the ratio of the productivity index for a damaged well to that of an undamaged well can be deduced using;

Behr and Raflee Model
In the assessment of reservoir p ressure support induced formation damage, the Behr and Raflee particle induced skin account is presented in equation (3.04) below; Where; is the Dimensionless particle induced skin factor is the Hawkins deduced skin factor is the Dimensionless coefficient of co mpletion for an oil well (0.50) is the equivalent radius, ft is the wellbore radius, ft is the reservoir radius, ft is the aquifer radius, ft is the radius of the sandstone particle, ft n is the dimensionless tortuosity index for porosity range. Though Equation (2.4) was orig inally modelled fo r a polymer injection process, with power law index of injected flu id n, this study replaces the power law index with the tortuosity parameter for each case study. The adaptation of the model to this study is validated since the value of the power law index in the study of Behr and Raflee falls within the tortuosity range of the various case studies to the analyzed. Therefore, the tortuosity of each reservoir sand foran overlapping circular-shaped sandstone formation as approximated in 1989 by Co miti et al. (Co mit i et al., 1989) will be deduced using Equation (2.8) is the dimensionless tortuosity magnitude. ᵽ is the formation packing factor for sandstone ∅ is the formation porosity 2.

Ozkan Model
The derived expression for the determination of fo rmation damage magnitude and additional pressure drop caused by the region of altered permeab ility around the wellbore as presented by Ozkan, (1997) at time, t and distance, r is given by; Where k r = √ k y k x (2.11) P wf (r ,x,t) is the wellbore flowing pressure at time t, psi P ws (r,x,t) is the pressure of the radial damaged interval r, at time t, psi L is the length of the well, ft qd is a dimensionless flux quantity qsc flux at the well surface, bbl/day/ft k r is the equivalent permeability of the x-y plane. Where; ∅ is the porosity of the reservoir μ is the oil viscosity (cp) c t is the total compressibility of the reservoir system, (psi -1 ) r w is the radius of the wellbore, (ft) P 1hr pressure interpolation on the Horner's plot at dt=1, (psi) Pwf is the wellbore flowing pressure before shut-in, (Psi) m is the slope of the Horner's plot, (psi/cycle).
One of the ways in which the productivity of a nonzero skin or non-zero format ion damage is quantified is by the Flo w Efficiency deduction. Denoted by the symbol F.E, it will be obtained through taking a ratio of the actual productivity index of each well (including skin) to the ideal productivity index if the skin factor were zero. Because the productivity index is the rat io of stabilized flow rate to pressure drop required to sustain that stabilized rate, the productivity indexes is presented in Equations (2.13) and (2.14) respectively. PI actual = q ( P ̅ −P wf ) (2.13) PI ideal = q (P ̅ −P wf − ( ∆P s )) (2.14) Consequently, the flow efficiency can be presented as; For a well with neither damage nor stimulat ion, F.E = 1; fo r a damaged well, F.E < 1; and for a stimulated well, F.E > 1. Again, it is important to note that for this study, the wells of interest fro m the various locations have no records of well stimulat ion( matrix acid izing or hydraulic fracturing) performed on them for the past 10 years. This is a desired analytical constraint because accurate flow efficiency estimation for ND will be distorted and results may truncate model choice of model establishment on co mplet ion of study. Equation (2.15) will be adopted for the efficiency of flow o f the well in a damaged subjected scenario for all 5 selected models Damage intensity of models will be evaluated in terms of Damage factor and Damage rat io. Damage factor is a dimensionless quantity used to evaluate the fractional percentage of production performance as a function of the damaged or altered permeability around the wellbore. Mathematically, it is presented as;

III. RESULTS AND DISCUSSION
Having computed reservoir rock and fluid data, production data, well parameters and other requisite parameters fro m five different Niger Delta reservoirs, a Matlab R2007 a program was written to generate a series of formation damage (skin) magnitudes for all five (4)    The closest to the buildup skin (s_i) was that of the Furui et al, (s_F) which was 3.81 and that of Ozkan overestimated the skin magnitude, record ing about 4.86 which when used for future reservoir performance forecast may prove erroneous in some flow and productivity analyses. Figure 4 above shows that for the ND-3 reservoir, the damage models for Oskan and that of Behr and Raflee can be used to estimate skin magn itude as it tends to have a closer reading to that of the reference skin model. Both having 2.96 as against 2.78 for that of the Buildup obtained skin magnitude, shows a considerable level of applicability. Again, for this reservoir, the skin estimat ion obtained fro m Frick and Economides model cannot be adopted as it shows an underestimation of fo rmation damage in the magnitude 1.21.

Fig.5: Formation Damage Magnitude (Skin) for Each Damage Model for ND-4
The ND-3 reservoir, having co mputed all reservoir rock and flu id parameters for skin estimat ion saw to the adaptation of the s_BR model as it recorded a damage magnitude of 4.78 as against the buildup damage estimat ion of 4.89. The Ozkan and Furui et al model slightly underestimated the damage magnitude as they both recorded4.14 and 4.08 respectively. At this point it is convenient to ascertain that the skin estimation form Frick and Econo mides cannot be used for damage analysis as it has proven to underestimate four reservoir skin magnitudes as shown in Figure 5 above. The model for Ozkan and Furui et al showed an encouraging applicability in the o ffshore reservoir, ND-5 as shown in Figure 6 above. The Behr and Raflee model was observed to have overestimated the format ion damage magnitude by 20% record ing about 1.820 in skin magnitude as against the 1.459 skin magnitude fro m buildup skin estimation. The 55.4% underestimation of fo rmation damage by the Frick and Economides model shows that sound engineering of reservoirs in offshore locations cannot be achieved using it as it tends not to proffer pro ximate skin values, It can be inferred fro m Figure 7 that the recurrent underestimat ion of formation damage fro m the Frick and Economides model is traceable to the fact that it does not incorporate certain intricate reservoir parameters that can influence formation damage. It seemed to be the simp lest expression, having only damage radius and damaged permeab ility considerations, tending to ignore other relevant parameters such as sand grain sizes, anisotropy of the system, tortuosity and other relevant parameters, especially for a Niger Delta oil bearing format ion that is characterized to the well sorted but poorly unconsolidated.

Pressure Drop Evaluati on 3.1.1 Skin Induced Pressure Drop
The additional pressure drop due to skin ∆Ps was calculated for each model using the Hawkins expression for all five reservoirs. Simulat ion results showed that the skin induced pressure drop for all models had an equivalent weighted average to their corresponding format ion damage magnitudes. Figure 8 belo w shows the variation in formation damage magnitude and the corresponding skin induced pressure drop, ∆Ps fo r all five damage models in ND-1.  Skin induced pressure drop (∆Ps ) analysis for the ND-3 reservoir revealed that since both the Ozkan and BR models had a close prediction of format ion damage in the magnitude of 2.96 for both models as compared to 2.78 skin magnitude for the buildup model, it can be inferred that for reservoirs producing within a rate of 800 stb/day range, both models can be adopted . With a 0.06% deviation fro m the reference model fo r both damage models with respect to pressure fro m due to skin, we can conclude that s_BR and s_O can be adopted for intermed iate production reservoirs within the Niger Delta.

Fig.11: Variation in Formation Damage Magnitude for all Damage Models with their Corresponding Skin Induced Pressure Drop, (∆Ps ) for ND-4.
The parameters fro m the offshore field showed a perfect superimposition for both formation damage magnitude and its equivalent pressure drop due to skin for all five models as presented in Figure 12 below. Th is is to say that a skin estimation of any magnitude, regardless of the authenticity or applicability of the model in the environment can yield a perfect and optimu m pressure drop with its corresponding formation damage degree.  The underestimat ion of skin and formation damage losses in pressure for the Frick and Economides model (s_FE) in all five distinct reservoirs goes a long way to confirm that skin magnitude estimation within the Niger Delta is not just a function of the damaged radius and damaged permeability, but also a function of certain petro physical properties peculiar to the Niger Delta region.

Reservoir Flow Performance 3.2.1
Flow Efficiency Analysis A unique method for the examination of format ion damage translation to a physically meaningfu l characterizat ion of our candidate Niger Delta reservoirs is by using the Flow Efficiency, (F.E) analysis. The adoption of Equation (2.15) and accurate simulat ion via Matlab R2007b with reservoir parameters for all five reservoirs and deductions fro m pressure transient analysis is represented in figure 18 to 22. The 83.7% prediction of Flo w Efficiency by the Frick and Economides model on the ND-1 reservoir may seem convincing and may influence the choice of model adaptation to reservoirs of such like properties. However, the non-incorporation of skin dependent parameters besides damaged permeability and damaged radius in the model has prompted this model to ignore certain intricate formation damage functions and thus tends to predict a high flowefficiency of 83.7%. This is as a result of the underestimat ion of the pressure drop due to skin, ( ∆Ps  Figure 14 shows  The models for Ozkan and Fu rui et al also showed proximal flow efficiency predict ions but were rather than that of the B-R model, with both having 56.56% and 57.09% flo w efficiency estimations. Th is is as a result of their lo w formation damage prediction which naturally tends to overestimate the reservoir production performance and efficiency. In the analysis of the offshore reservoir of ND-5, the Furu i et al model once again showed a good applicability in terms of flo w efficiency analysis.  As usual, the Frick and Economides model as presented by Yildiz in 2008 on evaluation via reservoir parameter simu lation with Matlab continuously underestimated formation damage magn itudes, predicted a lower pressure drop in an actual case scenario and overestimated well productivity performance by recording very high flo w efficiencies for all five (5) reservoirs that have been investigated.

Damage Intensity Analysis 3.3.1 Damage Factor -Flow Efficiency Relationship
The damage factor expression fro m Equation (3.13) y ielded a series of deductions from all 5 models for the five (5) Niger Delta reservoirs. The result translates that a higher flow efficiency will result in a lower damage factor, while a lower flow efficiency will incur a higher damage factor. This also applies to the damage ratio analysis relative to flow efficiency. The higher the flow efficiency, the lower the damage ratio and vice versa.    A higher production rate of 800stb/day for the ND -3 reservoir revealed that the Ozkan and B-R models are a good alternative for formation damage magnitude evaluation in terms of damage intensity (damage factor and damage ratio) analysis.

Fig.20: Variation in Flow Efficiency, Damage Ratio and Damage Factor for all Evaluated Damage Models in ND-3.
As shown in Figure 20 above, a damage factor of 0.36 and damage ratio 1.55 fo r both models could be said to match a 0.33 damage factor and a 1.50 damage factor deduction fro m the reference model. Th is goes a long way to ascertain than that at higher production rates, the Ozkan and B-R models mat be applicable p rovided parameter requirements are met for adequate simulation. The low production rate reservoir of ND-4 revealed that the B-R model suites best for these reservoir condit ions (petro physical, well and pressure transient properties) in terms of damage intensity as shown in Figure 21. Fo llo wing the Behr & Raflee model in terms of applicability was that of Ozkan and then that of Furui et al. The Offshore field having the highest production rate of 950 stb/day maintained that the models of Ozkan and Furui et al can the most applicable in terms of damage factor and damage ratio on parameter simu lation. Both models having a lower deviation from the standard skin model.

IV.
CONCLUSION The models presented in this work provide pred ictive tools for quantitative evaluation of formation damage estimates in Niger Delta reservoirs. The theoretical agreement obtained between predictions by the evaluated models for this study and format ion damage pred iction fro m the empirical pressure buildup skin model has been thoroughly analyzed. Skin usually referred to as formation damage is one of the major factors that influence a well or reservoir productivity. It tends to either promote or hamper production rates; it contributes greatly to pressure drop analysis in the entire production system, it influences well and reservoir deliverability and to some considerable extent, in fluences investment decisions and economic evaluation for candidate oil reservoirs part icularly for unconsolidated sand reservoir systems like those of the Niger Delta. In this work, one can clearly state that a comprehensive research and development study on the possible establishment of a unique format ion damage model in Niger Delta area has been carried out. The nu merical evaluation of these empirical models having incorporated their dependent variables yielded several series of damage responses. Critical evaluation on damage factor, damage rat io, flo w efficiency, effect ive wellbore radius, and skin induced pressure drop analysis proved to be reliab le analytical tools for the establishment of the unique model for the Niger Delta region. Judging fro m the skin magnitude estimat ion standpoint, with reference to the buildup estimated skin model, the models were streamlined to only three during the selection procedure as the Frick and Eciono mides model having skin as a function of only damaged rad ius, damaged permeab ility, wellbore rad ius and reservoir absolute permeab ility continuously underestimate skin values. This trend was observed for all five (5) reservoir cases leaving the models of Furui et al, Behr & Raflee and that of Ozkan to contend for the most suitable. The skin induced pressure drop analysis also translated the above mentioned case as the pressure drop due to skin is a function of the degree of damage to the format ion around the wellbore v icin ity. Flo w efficiency and damage factor investigation translated the application of all streamlined three (Furu i et al, Behr & Raflee and that of Ozkan) in a decreasing magnitude in the manner in which they appear for all five reservoirs.