Copyright © the author(s). This work is licensed under a Creative Commons Attribution 4.0 International License. Improved Oil and Gas Recovery DOI: 10.14800/IOGR.1349 Received January 5, 2025; revised March 1, 2025; accepted May 2, 2025. *Corresponding author: christian.okalla@futo.edu.ng 1 Technical Evaluation of Formation Damage Remediation in Niger Delta Clastic Reservoirs Anthony Ogbaegbe Chikwe, Christian Emelu Okalla*, and Prayer Samuel Diovu, Federal University of Technology Owerri, Owerri, Nigeria Abstract Formation damage continues to pose a significant challenge in hydrocarbon extraction, substantially hindering the productivity of reservoirs by diminishing the inherent permeability of the rock formations. This issue, which arises during drilling, production, or workover activities, results in subpar recovery efficiencies and considerable financial repercussions. The present investigation undertook a thorough technical assessment of formation damage and its remedial approaches for a well situated in the Niger Delta. In this study, pressure transient analyses were conducted on the buildup tests of Well P, both prior to and following acidization treatment.The PTA of Well P before acidizing revealed a positive skin value of +6.11 and a permeability of 3.15 mD, confirming the presence of considerable formation damage in the vicinity of the wellbore. To counteract this damage, a matrix acidizing treatment was executed, aimed at dissolving materials obstructing the pores and reinstating permeability. Post- treatment analysis indicated a skin factor of -0.658 and an improved permeability of 11.9 mD, signifying successful well stimulation and enhanced inflow performance. This research highlights the effectiveness of acidizing as a remedial measure in the clastic reservoirs of the Niger Delta, while also stressing the importance of combining technical diagnostics with economic assessments to enhance production efficiency and maximize asset value. Introduction Formation damage, a pivotal concept within the petroleum industry, pertains to the detrimental interplay between drilling activities and the productive formation. Such interplay results in a diminishment of permeability in the vicinity of the wellbore, thereby ultimately diminishing the productivity of the well. This phenomenon represents a widespread challenge encountered throughout the processes of well-drilling, completion, production, and workover within the petroleum sector. Bennion (2002) posits that formation damage refers to any process that degrades the inherent productivity of an oil or gas reservoir or the injectivity of a water or gas injection well. This study adopts the Niger Delta as a case in point. Klungtvedt and Saasen (2022) indicate that during drilling activities, interaction with drilling fluids can impair the formation's capacity for production or fluid flow. Dake (1978) describes the incursion of foreign fluids into the reservoir rock as creating a zone of diminished permeability within the wellbore, termed the "skin." It is important to note that formation damage is not exclusively a consequence of drilling or completion activities; rather, it arises from a multitude of intricate reservoir processes (Clifford 2019). In the development process, when the formation interacts with external fluids, physical and chemical reactions may occur if these fluids are incompatible with the reservoir fluids or mineral properties. These reactions can significantly impact the formation's productivity. The Niger Delta formation consists mainly of sandstone. As mailto:christian.okalla@futo.edu.ng Improved Oil and Gas Recovery 2 reported, the porosity of sandstone formations ranges from 10% to 35% due to the loose packing of individual sand or mineral grains. Raza et al. (2015) have shown that the permeability of sandstone reservoirs typically ranges between 0.4 md and 60 md. However, Fatt (1953) demonstrated that the application of overburden pressure decreases the permeability and porosity of sandstone reservoirs. Consequently, the Niger Delta region is characterized by relatively good porosity and permeability properties. Formation damage can be triggered by various factors and can occur at any stage of a well’s life. These factors affect the permeability of reservoir rocks, thereby reducing the natural productivity of the reservoir. To effectively evaluate formation damage, it is essential to investigate its root causes. This investigation is crucial for making informed decisions regarding the remedial actions to be taken on the well. Factors contributing to formation damage include erosion, chemical weathering, fluid injection, and overburden pressure. The technical evaluation of formation damage demands a multidisciplinary approach due to its complexity. Engineers can employ different strategies to address the problem of a damaged formation. A professional and in- depth understanding of formation damage is required to analyze data and solve problems accurately and comprehensively. Formation damage can result in substantial costs for remediation and deferred production (Oseh et al. 2015). Economic evaluation involves conducting a cost-benefit analysis of the financial impact. This includes assessing the lost revenue due to the reduced production rate caused by formation damage and the revenue generated from hydrocarbon production in the reservoir. Once formation damage occurs, the reservoir generally cannot return to its original state. The phenomenon where substances that enter the porous media do not easily exit is known as the reverse funnel effect (Porter 1989). Well testing is an effective method for determining whether a formation is damaged. By analyzing transient well-test data, the skin factor can be obtained (Renpu 2011). Pressure transient analysis, which involves the analysis of pressure and flow data sets, extracts information from pressure and rate data measured in a producing well (Alain 2018). Well testing can directly assess the degree of damage by matching a model (either analytical or numerical) of the well and reservoir to the data (Zarrouk and McLean 2019). Pressure transient analysis is one of the most valuable tools for evaluating formation damage (Denson et al. 2015). Well testing is primarily conducted to obtain information on the formation's permeability and skin factor, which helps in assessing well conditions and estimating reservoir parameters. Methodology The methodology employed in this study is well testing, a fundamental technique in petroleum engineering that involves measuring flow rates and pressure changes during production or injection tests. Among the various types of well-testing methods, this research focuses specifically on the pressure buildup well test. A pressure buildup test entails the measurement and analysis of bottom-hole pressure data after a producing well is shut in. In this study, pressure transient analysis was performed using KAPPA SaphirTM (developed by KAPPA Engineering), a reservoir modeling software, to characterize reservoir parameters, including permeability and skin factor. The data required for the analysis is stored in a spreadsheet, typically in Microsoft Excel format. This spreadsheet contains detailed information such as the pressure and time data collected during the test, along with other essential parameters necessary for a comprehensive analysis. Additionally, it includes the flow-rate data of the well and the pressures recorded with respect to time before the well was shut in. The process of loading data into the Kappa SaphirTM software for pressure transient analysis involves two key aspects: loading flow-rate data and loading pressure data. Loading Flow-rate Data. For the flow-rate data, which is measured in standard barrels per day (STB/D), it is sourced from a spreadsheet, usually in Microsoft Excel format. Once the software is set up with the correct data types and units, the “free” option is chosen in the format region. After specifying the appropriate time format for Improved Oil and Gas Recovery 3 the flow-rate data, it is imported into the Kappa Saphir software. Once loaded, the flow-rate data is presented in a history plot, enabling a visual representation of how the flow rate changes over time. Loading Pressure Data. Regarding the pressure data, it is also retrieved from an Excel spreadsheet. The data is organized in a two-column layout, with the first column showing time in hours and the second column presenting pressure in pounds per square inch absolute (psia). In the software, the relevant field is selected, and the correct data types and units are specified. The appropriate time format for the pressure data is then chosen. After importing the pressure data, a history plot is generated, plotting the pressure change against time. This plot helps in observing the pressure behavior during the test. After successfully importing the data into the software, several plots are generated, including the history plot, the Horner plot, and the log-log plot. These plots are invaluable for extracting the required reservoir parameters, such as permeability and skin factor. The permeability value provides insights into the state of the permeable spaces within the reservoir, while the skin factor serves as an indicator of well damage. A skin factor of zero indicates no damage, a negative value suggests well stimulation, and a positive value implies formation damage. By analyzing these values, it is possible to quantify the extent of damage inflicted on the formation. Results And Discussions Pressure Transient Analysis on Well P. The reservoir rock, fluid, and wellbore parameters for Well P (Table 1) provide foundational insights into the reservoir’s physical characteristics and fluid behavior, critical for interpreting pressure transient analysis. The reservoir thickness (h=200 ft) and porosity (φ=0.30) define a volumetrically significant formation with substantial hydrocarbon storage potential, given the high porosity— indicating 30% of the rock volume is pore space. This porosity, combined with the oil viscosity (µ = 0.8 cp), suggests favorable fluid mobility, as low viscosity reduces resistance to flow through the reservoir. The total compressibility (Cₜ=3×10⁻⁶ psi⁻¹) reflects minimal fluid and rock compression under pressure, which influences pressure propagation during transient tests. The oil formation volume factor (B₀=1.136 rb/stb) quantifies the expansion of oil from reservoir to surface conditions, aiding in converting subsurface volumes to stock-tank barrels for production calculations. Additionally, the wellbore radius (rᵢ=0.345 ft) directly impacts near-wellbore flow dynamics and skin effect calculations, which are essential for evaluating formation damage or stimulation efficiency. Together, these parameters underpin the reservoir’s storage capacity (φ∙h), fluid mobility (µ), and transient pressure response (governed by compressibility and viscosity), forming the basis for modeling well performance and optimizing acidizing interventions to enhance productivity. Table 1—Parameters used for pressure transient analysis. Reservoir rock parameters for well P Reservoir thickness (h) 200ft Reservoir porosity (ϕ) 0.30 The PVT Parameters for well P Oil viscosity (µ) 0.8cp Total compressibility of fluid (Ct) 3E-6ps-1 Oil formation volume factor (Bo) 1.136rb/stb The wellbore parameters Wellbore radius (rw) 0.345ft Improved Oil and Gas Recovery 4 The chosen interpretation models for pressure transient analysis (PTA) of Well P (Table 2) reflect a streamlined, conventional approach tailored to the well’s characteristics. The standard model was selected, indicating reliance on established methodologies for vertical wells in a homogeneous reservoir with finite boundaries, simplifying the analysis by assuming uniform reservoir properties and a defined spatial extent. The single-phase oil flow assumption aligns with the reservoir’s fluid phase, allowing straightforward interpretation of pressure responses without complexities from multiphase interactions. A single flow rate during testing further reduces variables, enabling consistent analysis of transient data under steady production conditions. The assumption of constant wellbore storage and skin implies stable near-wellbore dynamics during the test, which simplifies early-time pressure data interpretation but may overlook transient changes in formation damage or stimulation effects over longer durations. Together, these choices prioritize analytical simplicity and clarity, ideal for assessing baseline reservoir performance and evaluating acidizing impacts. However, homogeneity and finite boundary assumptions may limit the model’s ability to capture reservoir heterogeneities or long-term boundary effects, underscoring the need for complementary analyses if complex behaviors emerge post-acidizing. Table 2—Interpretation model for PTA of well P before and after acidizing. Interpretation models Chosen interpretation models Model option Standard model Well type Vertical Reservoir Homogenous Boundary Finite Fluid phase Oil Fluid flow rate Single flowrate Wellbore storage and skin Constant Table A within the Appendix furnishes the detailed pressure buildup test data acquired from Well P prior to the acidization procedure. The pressure buildup tests conducted on Well P prior to and after acidization (Table 3) elucidate significant operational and performance disparities.Before acidizing, the test spanned 57 hours (July 11- 14, 2022) with a liquid rate of 1,000 STB/d at shut-in, reflecting a prolonged period likely required to assess pressure recovery in a damaged well with restricted flow. Post-acidizing, the test duration shortened dramatically to 10 hours (October 22, 2022) under a higher liquid rate of 1,100 STB/d, signaling improved near-wellbore permeability and faster pressure stabilization due to reduced formation damage. The zero-rate shut-in during both tests ensured accurate measurement of reservoir pressure response, while the use of a single gauge-maintained data consistency. The shorter test duration post-acidizing underscores the treatment’s success in mitigating skin effects, enabling quicker reservoir evaluation and aligning with the increased production rate—a direct indicator of enhanced well productivity. These results highlight the acidizing intervention’s effectiveness in optimizing both operational efficiency and reservoir performance. Improved Oil and Gas Recovery 5 Table 3—History listings of the pressure buildup test before and after acidizing Before acidizing After acidizing Name of well Well P Well P Name of test Buildup test Buildup test Start date of buildup test 07/11/2022 10/22/2022 End date of buildup test 07/14/2022 10/22/2022 Time at start date of buildup test 03:00:17 12:00:00 Liquid rate at start time (STB/d) 1000 1100 Liquid rate at shut-in time 0 0 Duration of buildup test 57.0277 10.00 No of gauges used for the test Single gauge Single gauge PTA Result Analysis on Well P Before Acidizing. Figure 1 presents a historical plot of pressure (measured in psia) and liquid rate (in STB/d) against time (in hours) prior to acidizing. This plot effectively depicts two key aspects: the relationship between pressure and time, as well as the flowrate of the test over time. When examining the flow-rate plot, a distinct pattern emerges. During the initial flowing period, which lasts approximately 75 hours, there is a noticeable decline in pressure. This pressure decline is a characteristic phenomenon associated with the production of crude oil from the reservoir. As the oil is being extracted, the reservoir pressure gradually drops, which is a natural consequence of the reduction in the fluid volume within the reservoir. After the 75-hour flowing period, the well is shut in. Subsequently, a pressure build - up occurs over a period of 57 hours, which is the duration of the shut-in period. This process of pressure build - up after shutting in the well is the basis for what is known as a pressure buildup test. This test is crucial in petroleum engineering as it provides valuable insights into the reservoir's properties, such as permeability and the presence of boundaries. In summary, the figure offers a clear visual representation of the reservoir's behavior during the production phase (pressure decline) and the subsequent shut - in phase (pressure build - up), highlighting the key stages of a pressure buildup test before acidizing the well. Figure 1—The history plot of pressure (psia), liquid rate (STB/d) vs time (hrs) before acidizing. Figure 2 illustrates a Horner plot delineating the correlation between bottom-hole pressure (expressed in psia) and the logarithmic function of (tp+dt)/dt. The alignment of the data points on this plot with the derivative curve Improved Oil and Gas Recovery 6 is a critical indicator. This congruence substantiates the robustness of the model, offering a firm basis for conducting thorough and dependable analyses. Consequently, we can exhibit a high degree of confidence in the precision of the outcomes yielded by this model. The Horner plot serves a fundamental purpose in facilitating the computation of critical reservoir parameters. Through the examination of the curve's slope on the plot, engineers can precisely ascertain the permeability of the reservoir. Permeability, a crucial attribute, characterizes the ease with which fluids traverse the rock formation and is imperative for comprehending reservoir productivity. Furthermore, the plot allows for the determination of the skin factor, which quantifies the extent of damage or improvement in the vicinity of the wellbore, exerting a substantial influence on well performance. Furthermore, the Horner plot constitutes a valuable instrument for the identification of various flow regimes encountered during well testing. These flow regimes, encompassing the early transient, transient, late transient, and pseudo-steady-state periods, each exhibit unique characteristics indicative of the fluid flow behavior within the reservoir. The recognition of these flow regimes is imperative for reservoir engineers, as it facilitates the optimization of well production strategies, the prediction of reservoir performance, and the making of informed decisions pertaining to reservoir management. Figure 2—Horner plot of bottomhole pressure vs log (tp+dt/dt) before acidizing. Figure 3 illustrates a logarithmic scale graph depicting the correlation between differential pressure, pressure derivatives, and time (measured in hours). The curve positioned at the top of the graph signifies the pressure derivative (dp) plotted against time, whereas the curve located at the bottom corresponds to an additional pressure derivative (dp’) also plotted against time. Within the domain of petroleum engineering, the log-log plot is of paramount importance in ascertaining the wellbore storage constant (C). The concept of wellbore storage, which pertains to the retention and subsequent release of fluids within the wellbore under transient flow conditions, is fundamental. Through the examination of the curve characteristics on this log-log plot, engineers can precisely determine the value of C, a critical factor for comprehending well behavior and forecasting reservoir performance. Additionally, the vertical divergence between the two curves on the logarithmic scale plot has substantial implications for the skin factor. The skin factor is a quantifiable parameter that characterizes alterations in the vicinity of the wellbore resulting from factors such as formation damage or stimulation. A more pronounced vertical divergence between the two curves signifies a greater value of the skin factor. This correlation enables engineers to evaluate the extent of near-wellbore damage or improvement, which subsequently affects well productivity and the efficacy of reservoir management strategies. Thus, the log-log plot depicted in Figure 3 offers significant insights into wellbore storage and conditions in the vicinity of the wellbore, facilitating more precise reservoir characterization and optimization of well performance. Improved Oil and Gas Recovery 7 Figure 3—Log-Log plot of differential pressure (dp) and pressure derivative (dp’) vs Dt (hrs) before acidizing. The results from the pressure transient analysis before acidizing reveal critical insights into the well’s performance and reservoir characteristics (Table 4). The total skin factor of 6.11 indicates significant near- wellbore formation damage, which directly contributes to a pressure drop (ΔP) of 1,243.59 psi due to restricted flow efficiency. This damage underscores the necessity of acidizing to mitigate productivity losses. The reservoir’ s low permeability (3.15 md) and moderate permeability-thickness product (kh= 631 md·ft) suggest a thick but tight formation (~200 ft net pay), inherently limiting fluid flow despite the high initial reservoir pressure of 6,417.58 psia, which signals strong reservoir potential if damage is alleviated. The drainage radius of 214 ft and tested volume of 7.05 MMB further define the accessible reservoir volume, emphasizing the scale of recoverable resources. Combined, these parameters highlight a reservoir constrained by both natural tightness and induced damage, positioning acidizing as a critical intervention to enhance connectivity, reduce skin, and unlock the well’ s productivity aligned with the reservoir’s high-pressure potential. Table 4—Results of pressure transient analysis before acidizing. Model Parameters Values Units TMatch 31.7 [hr]-1 PMatch 0.00492 [psia]-1 C 0.00734 bbl/psi Total skin 6.11 kh 631 md×ft pi 6417.58 psia Wellbore parameters (tested well) C 0.00734 bbl/psi Skin (s) 6.11 Reservoir and boundary parameters Initial reservoir pressure 6417.58 psia Permeability thickness product (k*h) 631 md×ft Permeability (k) 3.15 md Derived and secondary parameters Drainage radius (re) 214 ft Tested volume 7.0514 MMB Delta P (Total skin) 1243.59 psi Improved Oil and Gas Recovery 8 PTA Result Analysis on Well P After Acidizing. Figure 5 depicts a dual-axis graph illustrating the relationship between bottom-hole pressure (in psia) and liquid flow rate (in STB/d) over time (in hours) during a well test. The analysis of the pressure transient reveals a 14-hour shut-in phase, wherein the well was sealed, resulting in a distinctive pressure buildup curve—a defining feature of a pressure buildup (PBU) test. The evaluation of near- wellbore conditions, reservoir permeability, and skin effects is critically dependent on this test, which analyzes the pressure recovery response subsequent to the cessation of production. The flow rate axis corroborates the shut-in event (0 STB/d) and offers context for the production rate prior to shut-in. The pressure buildup observed over a 14-hour period equips engineers with the means to ascertain crucial reservoir parameters, including formation transmissibility and initial reservoir pressure, which are indispensable for the optimization of subsequent interventions such as acidizing. This analysis highlights the pivotal role of the PBU test in diagnosing well performance and in guiding strategies for reservoir management. Figure 5—The history plot of pressure, liquid rate vs time after acidizing. Figure 6, which depicts a Horner plot, is evident that the data points correspond well with the derivative curve, indicating that the model is robust and suitable for our analysis. This facilitates the derivation of reliable results. The plot is instrumental in determining parameters such as permeability from its slope and the skin factor. Furthermore, the Horner plot enables the identification of various flow regimes pertinent to well testing, encompassing the early transient, transient, late transient, and pseudo-steady state periods. Figure 6—Semilog plot of bottomhole pressure vs. log (tp+dt/dt) after acidizing. Improved Oil and Gas Recovery 9 Figure 7 illustrates the differential pressure and pressure derivative as a function of time in hours. The upper curve corresponds to the pressure derivative (dp) plotted against time (hrs), whereas the lower curve represents the pressure derivative (dp') as a function of time (hrs). The log-log plot facilitates the calculation of the well bore storage constant (C). Additionally, it is understood that the vertical separation between the two plots is indicative of the skin factor, with a greater separation corresponding to a higher value of the skin factor. Figure 7—Log-log plot of differential pressure and pressure derivative vs. dt after acidizing. Table 5 provides a detailed analysis of the permeability results following the acidification treatment of Well P. The data presented in this table indicates that the permeability of the well has been measured to be 11.9 millidarcies (md). This value represents the ease with which fluids can flow through the rock formations surrounding the wellbore. Additionally, the initial reservoir pressure was recorded at an impressive 2667.83 pounds per square inch absolute (psia), reflecting the high energy status of the reservoir before any production activities commenced. Furthermore, the skin factor, a dimensionless parameter used to evaluate the condition of the wellbore and the near-wellbore formation, was calculated to be -0.658. A negative skin factor suggests that the acidification treatment has been successful in improving the permeability around the wellbore by removing or reducing damage caused by drilling muds, scales, or other factors that might have impeded fluid flow. This indicates an overall improvement in the well’s performance due to the treatment. Lastly, the wellbore storage coefficient was estimated to be 1.23 barrels per psi (bbl/psi). This coefficient quantifies the volume of fluid that the wellbore can store per unit of pressure change and is crucial for understanding the well's response to pressure changes during production or injection operations. A lower value of this coefficient implies that the wellbore is more efficient in transmitting reservoir pressure changes to the formation, which is generally a favorable characteristic for well performance. Improved Oil and Gas Recovery 10 Table 5—Results of pressure transient analysis from Saphir after acidizing. Model Parameters Values Units TMatch 0.71 [hr]-1 PMatch 0.0181 [psia]-1 C 1.23 bbl/psi Total skin -0.658 kh 2390 md×ft pi 2667.83 psia Wellbore parameters (tested well) C 1.23 bbl/psi Skin (s) -0.658 Reservoir and boundary parameters Initial reservoir pressure 2667.83 psia Permeability thickness product (kh) 2390 md×ft Permeability (k) 11.9 md Derived and secondary parameters Drainage radius (re) 214 ft Tested volume 7.0514 MMB PTA Result Comparison. Table 6 provides a detailed summary and comparison of three crucial parameters— permeability, skin factor, and wellbore storage coefficient—derived from the Pressure Transient Analysis (PTA) conducted on Well P both before and after the acidizing treatment. The data presented in this table clearly illustrate that the acidizing process has significantly improved the fluid flow characteristics in the vicinity of the wellbore. Specifically, there is a notable enhancement in permeability, which indicates a greater ease of fluid movement through the reservoir rock. Additionally, the skin factor, which is a measure of the near-wellbore damage or improvement, has decreased substantially, suggesting that the acidizing treatment has effectively reduced any damage and improved the well's productivity. Furthermore, the wellbore storage coefficient, which reflects the ability of the wellbore to store fluids, has also been positively impacted by the treatment. Overall, these findings unequivocally demonstrate that the acidizing treatment has successfully enhanced the production capacity of Well P by improving the fluid flow conditions near the wellbore. Table 6—Results of reservoir and wellbore parameters from Saphir before and after acidizing Well P. Parameters Before acidizing After acidizing Units Permeability (k) 3.15 11.9 md Skin factor (s) 6.11 -0.658 - Wellbore storage coefficient (C) 0.00734 1.23 bbl/psi Improved Oil and Gas Recovery 11 Conclusion Formation damage has been identified as the blockage of the permeable spaces of a reservoir. Technical evaluation has given room to professionally analyze a Niger Delta well from this project having a deep knowledge of what formation damage is and the properties of a Niger Delta formation which gave guide in validation of the results obtained during the analysis. The skin factor obtained before acidizing the well and Permeability value proved that the well was damaged. From the results obtained after acidizing the well, it has shown that acidization is one of the effective remedial actions that can be carried out on a sandstone formation to improve permeability and productivity of a well. Conflicting Interests The author(s) declare that they have no conflicting interests. References Alain, C.G. 2018. Everything You Always Wanted to Know About Well Test Analysis but Were Afraid to Ask. https://docslib.org/doc/1413322/everything-you-always-wanted-to-know-about-well-test-analysis-but-were-afraid-to- ask. Bennion, B.D. 2002. An Overview of Formation Damage Mechanisms Causing a Reduction in the Productivity and Injectivity of Oil and Gas Producing Formations. J Can Pet Technol 41(11):126-150. PETSOC-02-11-DAS Dake, L.P. 1978. Fundamentals of Reservoir Engineering. Amsterdam, Netherlands: Elsevier. Denson, A.H., Smith, J.T., and Cobbt, W.M. 2015. Determining Well Drainage Pore Volume and Porosity From Pressure Buildup Tests. SPE J. 16(4): 209-216. SPE-5595-PA Fatt. 1953. The Effect of Overburden Pressure on Relative Permeability. J Pet Technol 5(10): 15-16. SPE-953325-G Clifford, M. 2019. Numerical Evaluation of Formation Damage Models for Application in Niger Delta Oil Reservoirs. International Journal of Advanced Engineering Research and Science 6(5): 136-149. Klungtvedt, K.R. and Saasen, A. 2022. A Method for Assessing Drilling Fluid Induced Formation Damage in Permeable Formations Using Ceramic Discs. Journal of Petroleum Science and Engineering 213(1):1-15. Oluwagbenga, O. O., Oseh, J., Oguamah, I.A., et al. 2015. Evaluation of Formation Damage and Assessment of Well Productivity of Oredo Field, Edo State, Nigeria. American Journal of Engineering Research 4(3):1-10. Porter, K.E. 1989. An Overview of Formation Damage. Raza, A., Bing, C.H., Nagarajan, R., and Hamid, M.A. 2015. Experimental Investigation on Sandstone Rock Permeability of Pakistan Gas Fields. IOP Conference Series: Materials Science and Engineering 78(1):1-12. Renpu, W. 2011. Advanced Well Completion Engineering. Amsterdam, Netherlands: Elsevier. Zarrouk, S.J. and McLean, K. 2019. Geothermal Well Test Analysis. Amsterdam, Netherlands: Elsevier. Christian Emelu Okalla is a Technologist and Researcher at the Department of Petroleum Engineering, Federal University of Technology Owerri, Owerri, Nigeria. He holds both B.Eng and M.Eng in Petroleum Engineering from the Federal University of Technology Owerri, Imo State, Nigeria. His research interests are in drilling, production, natural gas, and reservoir simulation. https://docslib.org/doc/1413322/everything-you-always-wanted-to-know-about-well-test-analysis-but-were-afraid-to-ask https://docslib.org/doc/1413322/everything-you-always-wanted-to-know-about-well-test-analysis-but-were-afraid-to-ask Improved Oil and Gas Recovery 12 Appendix Table A—Field data obtained from Well P before acidizing. ∆t (hrs) Pws (psia) tp+∆t/∆t Q (STB/D) 0 6363.499 1000 0.00462 6342.726 16452.21212 1000 0.00924 6322.22 8226.606061 1000 0.01386 6301.943 5484.737374 1000 0.01848 6281.922 4113.80303 1000 0.0231 6262.127 3291.242424 1000 0.02772 6242.543 2742.868687 1000 0.03234 6223.182 2351.17316 1000 0.03696 6204.043 2057.401515 1000 0.04158 6185.135 1828.912458 1000 0.046654 6164.6 1630.128704 1000 0.052346 6141.827 1452.962465 1000 0.058733 6116.618 1295.062921 1000 0.0659 6088.786 1154.334789 1000 0.073941 6058.109 1028.910712 1000 0.082963 6024.368 917.1263887 1000 0.093086 5987.331 817.4985023 1000 0.104444 5946.758 728.7050554 1000 0.117188 5902.442 649.567816 1000 0.131488 5854.136 579.0366735 1000 0.147531 5801.723 516.175728 1000 0.165533 5745.04 460.1508488 1000 1.044442 4453.707 73.77050568 1000 1.171884 4383.539 65.85678143 1000 1.314875 4319.707 58.80366731 1000 89.75314 6175.142 1.846818277 1000 91.5533 6184.132 1.830167817 1000 Improved Oil and Gas Recovery 13 93.5731 6192.292 1.812248359 1000 95.83937 6199.78 1.793041564 1000 98.14937 6206.715 1.774376888 1000 100.4594 6213.18 1.756570578 1000 102.7694 6219.24 1.739564751 1000 105.0794 6224.957 1.723306615 1000 107.3894 6230.368 1.707747921 1000 109.6994 6235.504 1.692844483 1000 112.0094 6240.396 1.678555761 1000 114.3194 6245.07 1.66484449 1000 116.6294 6249.548 1.651676358 1000 118.9394 6253.84 1.639019721 1000 121.2494 6257.961 1.626845344 1000 123.5594 6261.924 1.615126177 1000 125.8694 6265.742 1.60383716 1000 128.1794 6269.428 1.592955035 1000 130.4894 6272.985 1.582458194 1000 131.2447 6276.422 1.579106128 1000 132.0000 6279.745 1.575792424 1000 132.0046 6282.961 1.575772272 1000 132.0092 6286.076 1.575752122 1000 132.0139 6289.097 1.575731972 1000 132.0185 6292.03 1.575711825 1000 132.0231 6294.876 1.575691678 1000 132.0277 6297.639 1.575671533 1000 132.0323 6300.324 1.57565139 1000