Buildup Tests Research Articles

Parametric Investigation of Gas Condensate Mobility versus Permeability in Multiphase Flow Reservoirs

The characterization of the gas condensate reservoir is complicated due to the multiphase flow of the fluid. The change of the composition of the excellent stream further makes it complicated. Such characterization is being done to measure the superb performance. To overcome this complexity, rigorous mathematical modelling is suggested for well test analysis. This mathematical modelling can be used to establish the correlation between well test analysis and well performance analysis. The research work is carried out to develop the analytical method to calculate the effective permeability of the gas condensate reservoir, gas condensate mobility and effects of mobility on the effective permeability. Here the different mathematical models are studied during the research work. The other correlations are used to determine the reservoir fluid's properties. Perrine’s method is used to estimate reservoir permeability. The research was carried out to analyze the effects of gas condensate mobility on permeability. In this work, the pressure build-up test data is analyzed, effective permeability ( ), gas condensate mobility and effects of gas condensate mobility are analyzed. This study found effective permeability and mobility by applying mathematical models, oil 14.603 mD, gas 0.148 mD and water 17.159 mD. Using the data obtained through the correlations, the calculated mobility (λ) of the oil, gas and water phase is 126.652 mD/cp, 13.454 mD/cp and 98.671 mD/cp, respectively.

E&P Notes (January 2022)

E&P Notes (January 2022)

Searching for reservoirs with bypassed oil using well tests and mathematical modeling

The increase of oil recovery by the involvement of bypassed oil into production is a significant source of oil production increase at a minimal cost. Bypassed oil zones identification possibilities researched through mathematical flow modeling and simulated well tests. Two hypothetical models of homogeneous and heterogeneous (with low permeability zones) oil formations were generated, in which the bypassed oil was trapped during the production. Based on these models, the authors calculated data of comprehensive well tests: buildup, drawdown and interference. The aspects of the well test interpretation results data obtained for both models through the best-match method allowed bypassed oil areas identification possibility assessment. A significant difference between the cumulative oil rate actually observed at the field and the one obtained in the model is the first diagnostic feature, which suggests the presence of bypassed oil. During the pressure buildup (drawdown) tests, the curves of pressure change derivatives on the Bourdet diagnostic plots for heterogeneous and homogeneous models differ significantly, which is the second diagnostic feature that suggests the presence of bypassed oil. The analysis of the data processing results obtained during the pressure buildup tests indicated cases of significant changes in conductivity over time which is associated with higher water cut due to the absence of any obstacles for water to flow through. This factor can be considered a third diagnostic feature. During the interference tests of a heterogeneous model in multiple directions, the permeability of the interwell space in all directions turned out to be much lower in comparison to the reservoir permeability in the vicinity of the wells, that is explained by the bypassed oil presence — this is the fourth diagnostic feature which suggests the bypassed oil presence in the interwell space. The obtained results of well test data interpretation means a possibility to identify undeveloped areas with bypassed oil, filtration model improvement and recommendations development of infill drilling or sidetracks for the residual reserves extraction. • The comprehensive well tests allows bypassed oil areas identification. • The presence of bypassed oil have an influence on Bourdet diagnostic plots at different time of production history. • The occurrence of bypassed oil cause obstacles for water to flow and slow down the change in conductivity. • The decrease of permeability according to the interference test results indicates the presence of bypassed oil.

Optimization model of material balance for reservoir energy survey analysis and control

Introduction. When monitoring the development of hydrocarbon fields, the energy state of the reservoirs is monitored. An inaccurate understanding of the current distribution of reservoir pressure leads to the wrong strategy for the development of residual oil reserves. Isobar maps are constructed to assess reservoir pressure for productive formation. The simplest and most common method of map generation (by interpolating the values of the measurements) has a high sensitivity to the coverage of the well stock by well tests and does not take into account the dynamics and compensation of fluid withdrawals. To eliminate these shortcomings, it is proposed to use the method of multi-tank material balance. Objectives. The purpose of the work is to show the possibility of using the multi-tank material balance method (MMB) to reduce the risks related to low current reservoir pressure at the stage of well workover planning under conditions of limitations on the number and duration of well tests and taking into account the history of production / injection, as well as to predict the dynamics of reservoir pressure in the drainage area. Methods. In the MMB model, for each well, its own block (tank) is specified, for which the mathematical balance equation is drawn up, taking into account the crossflow between the blocks. The transmissibility values are obtained iteratively by numerically solving the problem of minimizing the loss function of the discrepancy between the calculated reservoir and bottom hole pressures and their actual values. Results. The paper provides examples of good convergence of the calculated pressures by the MMB method to the actual build-up test results at the wells of the Ural-Volga fields. The possibility of predictive calculations to optimize the reservoir pressure maintenance system is shown. The practical advantages of the method are: relative simplicity of model, automated adjustment of interblock transmissibility. Discussion. The field of application of the MMB method is determined by the tasks in which it is necessary to determine the reservoir pressure in conditions of a lack of fresh measurements. The MMB methodology is applicable to assess reservoir pressure in order to remove risks before well workovers, as well as to predict the optimization of the reservoir pressure maintenance system.

Efficacy and Cost-Effectiveness of Phenotyping for Rice Resistance and Tolerance to Planthoppers.

Simple SummaryRice in Asia is damaged by a range of sap-sucking planthoppers. For the last 50 years, the main focus for integrated management of these insects was to develop resistant rice varieties. A single, bulk phenotyping test, known as the standard seedling seedbox test (SSST) was used to inform the majority of genetics and breeding programs for planthopper-resistant rice. However, there has been much debate over the efficacy of this test. We compared results from the SSST against those from a range of other phenotyping tests to assess how antibiosis and tolerance (the ability of rice to compensate for damage) affect test results, and how phenotyping might be improved to capture information regarding plant traits that are otherwise overlooked by the SSST. Based on the efficacy and costs of different tests, we recommend that breeding programs adopt a modified seedling seedbox test (MSST) when phenotyping 100s of rice lines but that insect performance tests that assess relative changes in planthopper biomass could be adopted when phenotyping fewer lines (e.g., <100 lines). The days-to-wilt (DTW) test was found to be particularly effective in segregating resistant/tolerant lines from susceptible lines.The standard seedling seedbox test (SSST) is the most prevalent phenotyping test in research on the genetics and breeding of planthopper-resistant rice. Using 16 rice lines that included plants susceptible, resistant and tolerant to the brown planthopper (Nilaparvata lugens), we compared the SSST to modified seedling seedbox tests (MSSTs) and the days-to-wilt (DTW) test. We also conducted a series of performance tests to assess nymph survival and development; adult longevity and egg-laying; egg survival; honeydew production; and plant weight loss. We also assessed the relative costs of the different phenotyping tests to better recommend test protocols that are suitable for high-throughput phenotyping. The SSST was found to be highly robust but fails to identify late-stage resistance; tolerance; or ovicidal responses. MSSTs improved phenotyping by identifying plants with low damage from planthoppers at later growth stages. Herbivore performance tests such as population or biomass build-up tests reduce space requirements and reduce setup and evaluation costs compared with bulk tests. They can also facilitate the assessment of plant tolerance; albeit with added costs. The DTW test most clearly segregates resistant and susceptible plants, thereby facilitating gene discovery and marker-assisted selection. We recommend that bulk testing be improved by switching from the SSST to a suitable MSST and that donor variety and pre-release lines be assessed for the nature of rice–planthopper interactions using biomass build-up tests—including the DTW test.

Improved vacuum system for high-power proton beam operation of the rapid cycling synchrotron

The vacuum system in the rapid-cycling synchrotron of the Japan Proton Accelerator Research Complex has been operated for more than 10 years. It becomes evident that the high-power beam operation has more powerful effects on the vacuum system than expected at the time of the design. Those effects of the high-power beam are categorized into two types of events, the malfunction of vacuum equipment and the large pressure rise. A specific example of the former event is the failure of the turbomolecular pump (TMP) controller by the full loss of a single-shot high-intensity beam. The TMP itself is also damaged by a bearing crush due to a touch down without braking the rotor. We have developed a TMP controller that can connect with long power and control cables of more than 200 m lengths. This length makes the controller be installed in a control room where there is no radiation influence. The TMP with high-strength bearing has been also developed. The TMP system becomes tolerant to a large loss of the high-intensity beam by using such a controller and a TMP. The latter event is an extreme pressure rise with increasing the beam power. The dynamic pressure behaviors during the beam operations are investigated to understand the outgassing mechanism by the beam. It is indicated that the pressure rise mechanism is a result of the ion-stimulated gas desorption. The analytical calculation based on the ion-stimulated gas desorption model well reproduces the measured dynamic pressure. The calculation also shows that, among the parameters, a larger pumping speed per unit length $s$ and a smaller initial surface density of the adsorbed molecules ${q}_{0}$ are required to suppress the extreme pressure rise. The nonevaporable getter (NEG) pumps are additionally installed to obtain the larger $s$ and smaller ${q}_{0}$. It is confirmed by simulating the beam line pressure distribution that the additional NEG pumps are effective to obtain the larger $s$ in every position along the beam line. The ability of the NEG pump to keep a low pressure during the vacuum system shutdown, which can contribute to maintain the small ${q}_{0}$, is examined by the buildup test. It is finally confirmed that the dynamic pressure during the high-power beam is effectually suppressed.

Calculation of Average Reservoir Pore Pressure Based on Surface Displacement Using Image-To-Image Convolutional Neural Network Model

The average pore pressure during oil formation is an important parameter for measuring the energy required for the oil formation and the capacity of injection–production wells. In past studies, the average pore pressure has been derived mainly from pressure build-up test results. However, such tests are expensive and time-consuming. The surface displacement of an oilfield is the result of change in the formation pore pressure, but no method is available for calculating the formation pore pressure based on the surface displacement. Therefore, in this study, the vertical displacement of the Earth’s surface was used to calculate changes in reservoir pore pressure. We employed marker-stakes to measure ground displacement. We used an improved image-to-image convolutional neural network (CNN) that does not include pooling layers or full-connection layers and uses a new loss function. We used the forward evolution method to produce training samples with labels. The CNN completed self-training using these samples. Then, machine learning was used to invert the surface vertical displacement to change the pore pressure in the oil reservoir. The method was tested in a block of the Sazhong X development zone in the Daqing Oilfield in China. The results showed that the variation in the formation pore pressure was 83.12%, in accordance with the results of 20 groups of pressure build-up tests within the range of the marker-stake measurements. Thus, the proposed method is less expensive, and faster than existing methods.

Pressure build-up test application in reservoir boundary structure determination

The design of highly efficient field development systems, their control and management require reliable information about the reservoir properties and structure of productive deposits. Among the most common and informative methods of obtaining information is well testing with the help of pressure build-up curves (PBU). The latter make it possible to study the structure and parameters of the farfield at a considerable distance from the well (tens and hundreds of meters), which allows to make informed decisions in the process of field development. Therefore, the use of PBU test interpretation methods in order to obtain maximum information is extremely relevant for hydrocarbon recovery processes. Well testing under nonequilibrium filtration conditions is one of the powerful tools for assessing the reservoir parameters, the structure of the farfield and assessing the well potential. The use of modern software tools for well test results interpretation allows to obtain much more information from the classical results, to clarify the structure of the field and the parameters of productive reservoirs. The aim of this work is to generalize the world experience of the farfield influence on the character of PBU and its derivative during well testing under nonequilibrium filtration conditions. The study has been conducted using the KAPPA Saphir software package, licensed for use by IFNTUOG for educational purposes. The above methods of PBU interpretation can be used to determine the farfield parameters and structure. On the basis of those one can make effective decisions on field development managing and during 3D geological models creation.

Time-normalized conductivity concept for analytical characterization of dynamic-conductivity hydraulic fractures through pressure-transient analysis in tight gas reservoirs

This paper presents a time-normalized conductivity concept to allow an analytical model for characterization of dynamically-closed fractures through pressure-transient analysis in tight gas reservoirs. Specifically, the fracture conductivity in our flow model is considered to be a function of time. With the definition of the time-dependent fracture conductivity in the model, calculation of variable-rate pressure-transient behavior (e.g., pressure buildup tests) can be still based on the solution of linear differential equations governing fluid flow in a gas reservoir. Therefore, the superposition principle can be legitimately utilized in our solution to model pressure buildup tests. We then introduce a modified exponential function to represent the decline behavior of the time-normalized fracture conductivity during the production stage, and the dynamic fracture conductivity is essentially handled in a stair-step manner to calculate bottom-hole pressures. The accuracy of the calculated transient pressures was validated by comparing with a commercial simulator. The pressure drawdowns at early-times, because of dynamically-closed fractures, clearly increase more than in the invariant-fracture-conductivity case. We examine the effects of fracture conductivity behavior and production history on the pressure-transient response extensively, and use them to help identify the presence of dynamically-closed fractures. Finally, we demonstrate the influence of dynamically-closed fractures in synthetic and field cases to show the utility of the methodology. Results indicate that integrating multiple pressure build-up data obtained in different production periods enable us to diagnose and then to understand the changes in fracture conductivity during reservoir depletion. Using the results from the multiple pressure-transient analyses, this method can further be used to forecast the trend of fracture conductivity changes.

An Improved New Convolutional Neural Network Method for Inverting the Pore Pressure in Oil Reservoir by Surface Vertical Deformation

Abstract Average pore pressure in oil formation is an important parameter to measure energy in the formation and the capacity of injection–production. In past studies, average pore pressure mainly depends on pressure build-up test results, which have a high cost and need a long testing time, so it is not conducive to utilize. In this paper, the vertical deformation of the Earth’s surface was used to calculate changes in reservoir pore pressure. We set up the marker stake for measuring ground displacement and measured the vertical deformation at the in situ position. Furthermore, we provided an improved new convolutional neural network (CNN), which adopted image-to-image mode, removed pooling layers and full connection layers, and used a new loss function considering the boundary influence coefficient matrix. Then, the machine learning method was used to invert surface vertical deformation to change pore pressure in the oil reservoir. The method was tested in the block of the Sazhong X development zone, in the Daqing Oilfield of China. The average pore-pressure change values of 20 grids whose area was 900×900 m each were determined by the inversion of the corresponding surface vertical deformation at 27 marker stakes. The pore pressure change accuracy reached 82.34%. This study provides a new method for calculating average pore pressure in terms of an oil block. At the same time, it also provides a new technical method for inversion calculations.

Determining Reservoir Model Based on Welltest Analysis for Production Forecasting

Welltest analysis is basically an analysis of fluid flow behavior in porous rocks, both in oil reservoirs and gas reservoirs that aim to obtain reservoir characteristics. Welltest analysis is not only limited to get reservoir characteristics and well productivity, but to determine the reservoir and boundary models that are close to the real situation. Until now, to determine the reservoir and boundary models are usually assisted by using a simulator, which is called modeling. However, to determine the reservoir and boundary models has its own challenges, because there are no specific methods or equations that can know for certain the model of a reservoir. Choosing the right type of model also requires some consideration, such as seismic data, geological data, log data, and information provided from other wells drilled into the same formation. From the determination of this model can be used as supporting information for a reservoir, which is then used to be a predictive model and renewal of its geological model, as well as allowing engineers to simulate production estimates. In this paper, we will present an analysis of determining the right reservoir model based on welltest analysis, which selected model is used to simulate production estimates. Case example is taken from an oil well named "HBR-05", which has been carried out a pressure build-up test on one productive layer that until now has not been produced or closed since the well testing was carried out. From the determination of the reservoir model based on welltest analysis, obtained heterogeneous anisotropic reservoir model and rectangular-no flow boundary model. The selected reservoir model is used to simulate the estimated production of the "HBR-05" well if it is produced from this layer. Production forecasting results for 48 months (4 years) the "HBR-05" well, the cumulative production is 107.8 Mbbl. In addition, the results of forecasting show that the reservoir pressure is already below the bubble point pressure in the 22nd month of forecasting.

Study on Development of Shale Gas Horizontal Well With Time-Phased Staged Fracturing and Refracturing: Follow-Up and Evaluation of Well R9-2, A Pilot Well in Fuling Shale Gas Field

In the development of the Fuling shale gas field, for the first time, Well R9-2 was selected for a test of time-phased staged fracturing and refracturing treatments to study the effectiveness of fracturing at each stage for a novel development approach exploration. This paper introduces the design of the experiments, analyzes the results, and provides a follow-up evaluation of the entire development process. As of 9 August 2020, the well had gone through three phases of development. Phase I: time-phased staged fracturing and development for Stages 1–2, 3–4, 5–6, and co-development for Stages 1–6; Phase II: Stages 1–6 were developed once more after refracturing; Phase III: sealing the sections in Stages 1–6, then fracturing and development of Stages 7–19. Pressure build-up tests were conducted during the development of Stages 1–2 and 3–4, and gas production profile logging and microseismic monitoring were performed during the co-development of Stages 1–6. The results show that the combination of time-phased staged fracturing and refracturing treatments can fracture each stage more effectively. The pressure build-up test can effectively obtain the reservoir parameters of developed shale gas wells. The potential of refracturing treatment in a developed well can be identified from the gas production profile logging and microseismic monitoring. The findings are of this study productive for enhanced shale gas recovery; the combined pattern of time-phased staged fracturing and refracturing acts as a direct guideline to future shale gas production.

A Rapidly Deployable Test Suite for Respiratory Protective Devices in the COVID-19 Pandemic.

Introduction:The current COVID-19 pandemic has caused large shortages in personal protective equipment, leading to hospitals buying their supplies from alternative suppliers or even reusing single-use items. Equipment from these alternative sources first needs to be tested to ensure that they properly protect the clinicians that depend on them. This work demonstrates a test suite for protective face masks that can be realized rapidly and cost effectively, using mainly off-the-shelf as well as 3D printing components.Materials and Methods:The proposed test suite was designed and evaluated in order to assess its safety and proper functioning according to the criteria that are stated in the European standard norm EN149:2001+A1 7. These include a breathing resistance test, a CO2 build-up test, and a penetration test. Measurements were performed for a variety of commercially available protective face masks for validation.Results:The results obtained with the rapidly deployable test suite agree with conventional test methods, demonstrating that this setup can be used to assess the filtering properties of protective masks when conventional equipment is not available.Discussion:The presented test suite can serve as a starting point for the rapid deployment of more testing facilities for respiratory protective equipment. This could greatly increase the testing capacity and ultimately improve the safety of healthcare workers battling the COVID-19 pandemic.

A new physical modeling for two-phase wellbore storage due to phase redistribution

Pressure transient analysis is one of the main dynamic sources for reservoir characterization. The main task in well test interpretation is to understand the reservoir properties using the bottom-hole pressure behavior. Unfortunately, one of the main factors that can affect this task is wellbore storage effects, especially in cases that we have a non-ideal one. In pressure build-up test if pressure is below the bubble point or if gas enters into the wellbore, the phase redistribution can happen during the shut-in period. This phenomenon causes pressure anomalies. Besides, due to pressure increase or existence of under-saturated liquid in the wellbore, the gas starts to dissolve, and it is led to pressure decrease. So the pressure build-up test is dominated by three main factors: firstly, the pressure increase resulted from build-up test. Secondly, the pressure increase due to phase redistribution. Finally, the pressure decrease due to gas dissolution. These effects are known as non-ideal wellbore storage. Most of the studies focused on non-ideal wellbore storage try to propose an empirical equation to simulate the pressure curve more accurately instead of proposing an analytical model, because of the large number of effective parameters in an actual case.This paper is proposing a new analytical model for changing wellbore storage and analysis of gas phase segregation during the pressure build-up test in the existence of the under-saturated liquid. This model is further modified for two-phase flow when pressure falls below the bubble point in the wellhead. When the well is shut in at the start of build-up test, gas bubbles travel upward because of the buoyancy force. This model is presented for the case of dissolving gas pockets while rising in the wellbore. The novelty of this paper in comparison to previous researches is in developing a new physical model for two-phase wellbore storage done by modeling pressure increase due to gas bubbles rise while modeling gas dissolution against time.In this study, first, the basic assumptions for simplifying the model are described and the basic theory behind the proposed model is explained. Then a simple model without gas dissolution, using Laplace transformation, is introduced. Next, the modified model considering gas dissolution effect is proposed. A synthetic case is considered and the corresponding well test type curves are generated using the proposed method. Finally, the comparison between the proposed model and a real build-up case is made. The result is consistent with the typical non-ideal wellbore storage that is seen in the literature.

Contribution of Tidal Analysis to Reservoir Monitoring: A Field Case Study in a Fractured Reservoir Offshore Abu Dhabi, UAE

Summary Offshore reservoirs are subjected to pressure loading from the ocean tide. The resulting pressure fluctuation, notably its amplitude and phase, provides valuable information regarding the formation compressibility and heterogeneity. The purpose of the present study is twofold: First, to propose a method for calculating tidal efficiency from harmonic analysis of regional tide stations and detrended bottomhole pressure (BHP), and second, to compare the compressibility from tidal analysis with that obtained from rock-mechanics measurements and material balance. This case study is on a fractured oil field for which matrix laboratory measurements alone cannot capture the large-scale formation compressibility that is driven by the fracture distribution. This paper will show how, in the absence of seabed-pressure measurements, a synthetic diurnal tide can be simulated by interpolating the harmonic constituents of neighboring tide stations. The validity of this method was confirmed on two offshore fields. A new procedure that combines a Savitzky and Golay (1964) (SG) filter and cubic splines gave satisfactory results to filter out the tidal signal residual from the reservoir-transient response for both buildup and interference tests. In addition, this paper found that wells in fractured areas of the field have higher rock compressibility and exhibit a higher tidal efficiency. The same effect is observed in flank wells with higher water saturation. Conversely, the tidal efficiency is dramatically reduced in wells experiencing gas breakthrough.

Determination of in-situ elastic properties and reservoir boundary conditions

The elastic properties of reservoir formation are usually measured through laboratory triaxial tests or are estimated from empirical correlations obtained from well logs. Both approaches have similar limitation of the estimated value being representative of near-wellbore region. The former, however, has the further limitations of being costly and the unavailability of core samples for having a reliable estimate. In this paper, a new methodology is presented to determine the in-situ elastic properties (Poisson's ratio-PR- and Young's modulus) using pressure transient testing. Adopting the poroelasticity theory, a generalized diffusivity equation is formulated incorporating reservoir deformations into the fluid flow. By applying different boundary conditions, namely generalized plane stress, plane strain, and uniaxial strain, several analytical solutions were developed to obtain the PR from well testing. It shall be noted that the Young's modulus can be estimated given PR and bulk modulus. Two field data sets were used to implement and validate the proposed methodology for estimation of the PR (a build-up test data-set from a limestone oil reservoir and an interference drawdown well testing data-set from a sandstone aquifer). Results indicate that indeed the PR is a strong function of the reservoir deformational behavior. Moreover, estimation of PR under different boundary conditions provide a tool to identify the dominant reservoir deformational conditions. This was identified for the first data set by having the sonic well log data available and for the second data set by comparing the pressure-time measurements with their counterparts obtained from fully coupled fluid flow/geomechanics simulations. Moreover, once the validity of the output is confirmed by comparison with the available PR from well logging and/or coupled flow/geomechanics simulations, the proposed protocol can be re-used multiple times during reservoir life to estimate the elastic properties under the appraised BCs, without the necessity to run new well logs or lab tests.

A well-testing method for parameter evaluation of multiple fractured horizontal wells with non-uniform fractures in shale oil reservoirs

Owing to intricate geological and engineering factors, the hydraulic fractures in shale oil reservoirs sometimes are in heterogeneous and random lengths, which brings a difficulty in fracture estimation. To improve this situation, a simple and quick well-testing method is presented for fracturing evaluation and parameter estimation of multiple fractured horizontal wells with non-uniform fractures. The semianalytical method and Laplace transformation are used for model solution. With the proposed model, we estimate the properties of non-uniform fractures in shale oil wells from the Ordos Basin based on the buildup testing data. Results from the case studies show that there is a good relationship between fracturing treatment parameters and generated fracture properties, including fracture length and storativity ratio (or fracture volume ratio). The fracture parameter values increase with the increase in fracturing liquid volume, especially the inner region permeability and storativity ratio. When the fracturing liquid volume per stage increases by 200-300 m3 , the fracture impacts are weaker on generated parameters, which indicates that there would be an optimized fracturing liquid volume in the field case. Cited as : Meng, M., Chen, Z., Liao, X., Wang, J., Shi, L. A well-testing method for parameter evaluation ofmultiple fractured horizontal wells with non-uniform fractures in shale oil reservoirs. Advances in Geo-Energy Research, 2020, 4(2): 187-198, doi: 10.26804/ager.2020.02.07

A model for calculating bottom-hole pressure from simple surface data in pumped wells

Bottom-hole flowing pressure and pump intake pressure (PIP) are important parameters to optimize the performance of oil wells. In recent years, downhole sensors are becoming widely used in electrical submersible pump systems to measure these pressures. However, it is still rare to use downhole sensors in sucker rod and progressive cavity pumped wells. In this study, two correlations were developed to calculate bottom-hole flowing pressure and PIP from readily available field data. The two correlations do not require measurements of buildup tests, but they rely on measuring the dynamic fluid level and estimating fluid gradient correction factor using either (1) the tubing gas flow rate or (2) the annular gas flow rate. Then, the PIP is calculated by the summation of either (1) the tubing pressure plus the tubing gaseous liquid column pressure or (2) the casing pressure, annular gas column pressure and the annular gaseous liquid column pressure. The correlations were developed using 419 field data points (389 points for training and 30 for testing) of wide range for each input parameter. Using the training data, the mean absolute percentage deviation (MAPD) between the calculated and measured PIPs is 25% and 20% for the first and second correlations, respectively. However, the testing data showed MAPD of 33% and 12% for the first and second correlations, respectively. The accuracy of these correlations is significantly higher than that of the previously available methods, and the correlations require simpler input. Such study is an original contribution to calculate the PIP with improved accuracy and without downhole pressures sensors.

Flow Regime Analysis on Pressure Build-up Test Result of Z-01 Well Using Dual Porosity Reservoir Model

Flow regime analysis on the results of pressure build-up Z-01 well test was conducted to determine the type of flow that occurs in each time region section. In the early time stage there is a flow which is dominated by linear flow which is then followed by bilinear flow. At the middle time there is a radial flow where the pressure disturbance has spread towards the reservoir. In the late time flow stage is dominated by steadystate flow where the flow is affected because there is a support pressure caused by the constant pressure boundary. In the analysis of pressure build-up used to determine reservoir parameters can be used in the middle time region. This is used because the plot results between ΔP vs. log HTR (Horner Time Ratio) are straight lines which can be used to calculate reservoir parameter values such as permeability (k), formation damage factor (s). This test was analyzed using the Ecrin software and obtained a dual porosity model with a permeability value of 4.8 md, skin -3.57. From the analyzed model, it is obtained that the well fracture-finite conductivity model means that the Z-01 well has been stimulated to increase production.

Thermal impacts on pressure transient tests using a coupled wellbore/reservoir analytical model

This work investigates the impact of temperature effect on pressure-transient measurements made at any gauge location along a slanted wellbore completed with a production tubing. The analysis is based on a coupled transient-wellbore/reservoir thermal analytical model, which considers flow of a slightly compressible, single-phase fluid in a homogeneous infinite-acting reservoir system. The analytical model provides temperature- and pressure-transient data for drawdown and buildup tests, accounting for Joule-Thomson, adiabatic fluid-expansion, conduction and convection effects. Regarding pressure transient analysis (PTA), thermal distorted pressure data might lead to the interpretation of false geological heterogeneities, because the transient heat loss during the buildup period provides an increase in the pressure exerted by the wellbore-fluid column and a change in the gauge location due to pipe contraction. Though some of the derived expressions are lengthy, they encompass an intrinsic simplicity in that one can compute pressure- and temperature-transient data on a spreadsheet. Analytical results are compared with those of a commercial thermal wellbore/reservoir simulator showing a good agreement. Thermal impacts on PTA interpretations are demonstrated by showing that a homogenous reservoir can be wrongly interpreted as a double-porosity system. A field case is presented, consisting of a drill stem test conducted in a multi-layered heterogeneous reservoir.