Buildup Tests Research Articles

Applying hydrodynamic principles and flow theory to optimize the reservoir pressure survey program without shut-in the well - Case study: Biba reservoir, Algeria

The article focuses on the importance of gathering and analyzing information related to oil and gas reservoirs, particularly parameters such as permeability (k), skin factor (S), pressure (p), and temperature (T). This data is crucial for making significant decisions in adjusting production technologies, intervening in wells, and near-well bore treatment. To obtain this information, analyzing data from tests is essential. Pressure, flow rate, and time data are collected using pressure buildup testing, where wells are produced at a constant rate and then shut-in to observe pressure increase over time. Analyzing this data allows evaluation of permeability, pressure in the drainage region, skin factor, and other parameters like static pressure. The article also discusses applying principles of hydrodynamics and flow theory to optimize well pressure survey programs without disrupting production operations. This method enables the collection of necessary information while maintaining continuous field operations and providing comprehensive technological data. The results were applied on Bali reservoir in Algeria. Information gathered from pressure survey programs not only helps fine-tune and optimize daily production procedures but also significantly contributes to updating reservoir models. This serves as a basis for future development decisions within the reservoir. The method has been successfully applied at Biba field, Algeria.

Analysis of Field Data Using Microsoft Excel and MATLAB Software to Evaluate Reservoir and Well Damage

Reservoir formation damage is a drop in a well's productivity caused by a decrease in reservoir rock permeability. To tackle this issue and maximize well production, obtained pressure build-up time data at a steady production rate from a vertical producing oil WELL 20A, was analysed to establish the wellbore and reservoir characteristics. A numerical well test simulator (Matlab) is used to simulate damage in the area close to the wellbore, a Microsoft Excel sheet and an analytical approach to calculate the impact of wellbore and reservoir factors such as skin, wellbore storage, and average reservoir permeability. In order to determine whether the numerical well test simulator was successful at performing pressure transient analysis on observed data, the findings from the analytical solutions using Microsoft Excel Sheet and numerical well test simulator Matlab were compared. Comparable outcomes for the permeability and skin values were obtained from the build-up test data analysis generated; hence, the negative skin values for wells 20A acquired after the analysis suggest that the formation is not damaged. This indicate that well 20A is not a candidate for workover operations.

PRESSURE BUILD-UP TEST ANALYSES OF A HYDRAULICALLY FRACTURED WELL WITH REDUCED HALF-LENGTH

When the oil production of the hydraulically fractured well A-1 began to decline, a refracturing of the well was planned, as a reduction in the fracture size was assumed after a long production period. Several possibilities of the pressure build-up test analyses were performed to determine the best evaluation of the reduced fracture half-length. Although the objectives of these tests are to determine the reservoir properties, such as rock permeability and skin factor, as well as fracture conductivity, the Saphir programme is also used to model the fracture half-length. This is the most important parameter required for the design of the new fracturing process and for the creation of a new production model. For this purpose, the methods of the pressure build-up test analysis are first described theoretically. Based on different analyses of the same pressure build-up test, the one that best matches the analytical model of a fractured well with the measured pressure curve and the derivative curve is selected. It is found that the most accurate result for fracture half-length is obtained from the fractured well model with multiphase flow.

Develop an empirical flow rate correlation to model wellbore storage phenomenon for wells produced at a constant wellhead pressure

Well-test operation with a constant flow rate for long-time production is not typical in practice. Therefore, reservoirs frequently produce fluids with constant pressure at the wellhead, into a constant pressure separator or pipeline. During the production under this condition, the pressure drop at the wellbore varies as a function of the rate because of changes in the friction flow; therefore, the wellbore formation pressure is not constant. As a consequence, the wellbore storage effect emerges and should be incorporated in the modeling of fluid flow under production at a constant wellhead pressure. All available methods considering the wellbore storage effect can merely be applied for production under the constant rate condition. Moreover, well-test modeling under these circumstances needs a specific function for production rate, which made this type of well-testing less common. Even though there are exact solutions for production under the constant wellbore pressure in the Laplace domain, their inverse transform is quite complex and cannot be applied for modeling the wellbore storage effect. In this study, a new function is introduced as an approximate solution of the diffusivity equation, for a well that produces at a constant wellbore pressure, using multiple steps of the optimization process. Consequently, an efficient correlation is developed for flow rate about or concerning this condition. Next, the effect of the wellbore storage at constant pressure well-test operation was enumerated for the first time, which was commonly neglected in previous studies. This endeavor concentrated on modeling the two types of well-test operation, producing at constant wellhead pressure and, pressure build-up following the production at a constant wellhead pressure (constant pressure Build-up test). The results were also verified with numerical simulation as well as field data further confirming the excellent accuracy of developed solutions.

CRM-Aquifer-Fractional Flow Model to Characterize Oil Reservoirs with Natural Water Influx

Summary This work presents a new flow model that uses production data to characterize conventional undersaturated oil reservoirs with natural water influx in primary production. The main application is to estimate the original oil in place (OOIP), but the model also calculates the productivity index (PI), water influx, and heterogeneity factor. Aquifers are common to many reservoirs and their diagnosis is relevant because they can serve as an important drive mechanism but can also affect well productivity. Discerning between the reservoir and aquifer volumes is also a major challenge in many oil fields. Reservoir-aquifer systems have been investigated with various dynamic characterization techniques such as the material balance equation (MBE), pressure transient analysis, and production/rate transient analysis. These methods have limitations, for example, requiring shut-in wells and/or very large production histories and high mobility and compressibility ratios to yield distinguishable responses in the diagnostic plots. The new flow model couples the producer-based capacitance resistance model (CRMP) with the Fetkovich aquifer model (CRMPA). It enables calculating the total instantaneous production flow rate from a well as a function of three mechanisms—reservoir depletion, changes in bottomhole pressure (BHP), and water influx. In addition, CRMPA is coupled with the Koval fractional flow model (capacitance resistance aquifer-fractional flow model, CRMPAF) to calculate the individual oil and water rates and to enhance the OOIP estimation for wells with two-phase production caused by water breakthrough from the aquifer. The capacitance resistance model (CRM) is a production analysis technique that uses rate and pressure data from typical field surveillance (no dedicated tests) to characterize reservoir properties. It has been widely used to study reservoirs under secondary and tertiary recovery. There are a few applications for primary recovery, and only one reference investigated natural water influx. There are important differences between the previously published and the new CRMPA formulations. The former estimated the individual water influx to each well in a multiwell reservoir associated with an aquifer. The calculations were performed assuming the reservoir pore volume (PV) was known, whereas the present approach simultaneously calculates the PV and the water influx. The former approach also required a priori knowledge of the average pressure, obtained from buildup tests, whereas the new method uses production data, (i.e., it does not require shut-in wells). In the new approach, CRMP (without aquifer) is first used to calculate the capacitance/resistance (CR) parameters of the equivalent (reservoir-aquifer) medium. It provides the correct OOIP for volumetric reservoirs; however, CRMPA is used when the PV significantly differs from volumetrics and water influx is detected. CRMPA calculates the reservoir CR parameters using simple relationships between the equivalent and composite mediums. For wells with two-phase production, the Koval factor is an additional parameter. The CRMPA/F solution is obtained by minimizing the errors between the calculated and measured rates over a time window. The new CRMPA/F approach is compared and validated with several models of single and multiwell synthetic reservoir-aquifer systems with different properties and geometries. It is also used to characterize a field case.

Categories of resistance in cotton genotypes, Gossypium spp. against cotton-melon aphid, Aphis gossypii (Hemiptera: Aphididae).

Cotton-melon aphid, Aphis gossypii Glover (Hemiptera: Aphididae), is emerging as a potential threat to cotton cultivation worldwide. The resistance categories in Gossypium arboreum to A. gossypii still need to be explored. We screened 87 G. arboreum and 20 Gossypium hirsutum genotypes against aphids under natural field conditions. Twenty-six selected genotypes from these 2 species were tested under glasshouse conditions for resistance categories (antixenosis, antibiosis, and tolerance). Resistance categories were assessed by no-choice antibiosis assay, free-choice aphid settling assay, cumulative aphid days using population buildup tests, chlorophyl loss index, and damage ratings. No-choice antibiosis experiment revealed that the G. arboreum genotypes GAM156, PA785, CNA1008, DSV1202, FDX235, AKA2009-6, DAS1032, DHH05-1, GAM532, and GAM216 had a significant adverse effect on aphid development time, longevity, and fecundity. Gossypium arboreum genotypes CISA111 and AKA2008-7 expressed a low level of antixenosis but possessed antibiosis and tolerance. Aphid resistance persisted uniformly at different plant developmental stages studied. The chlorophyl loss percentage and damage rating scores were lower in G. arboreum than in G. hirsutum genotypes, indicating the existence of tolerance in G. arboreum to aphids. Logical relations analysis of resistance contributing factors depicted the presence of antixenosis, antibiosis, and tolerance in the G. arboreum genotypes PA785, CNA1008, DSV1202, and FDX235, indicating their utility for evaluating the mechanisms of resistance and aphid resistance introgression breeding into G. hirsutum to develop commercially cultivated cotton lines.

Pressure transient analysis to investigate a coupled fracture corridor and a fault damage zone causing an early thermal breakthrough in the North Alpine Foreland Basin

The heterogeneity of the Upper Jurassic carbonate reservoir (Malm reservoir) beneath the North Alpine Foreland Basin has a significant influence on the mass and heat flow processes during geothermal exploitation. Geophysical borehole data revealed that sub-seismic scale fractures and karstified fractures occur at the inflow zones of deep geothermal wells. However, pressure transient analysis (PTA) in some previous studies concluded that it is difficult to detect the influence of sub-seismic scale features, suggesting that radial flow regime is dominant. Accordingly, a regional thermal-hydraulic model adopted the equivalent porous medium (EPM) approach, homogenizing the sub-seismic scale reservoir heterogeneities; however, unable to detect an early thermal breakthrough (ETB) in a geothermal doublet located SE of Munich. We apply PTA on three buildup tests belonging to that doublet following a deterministic approach to constrain the reservoir type by interpreting the pressure derivative (PD) plots constrained by geophysical and geological data. We derive the magnitudes of the reservoir hydraulic parameters by matching the PD plots with the selected interpretation models. We find that clustered fractures have a significant influence on the reservoir hydraulics, evidenced by trough-shaped curves in the PD plots. Linear flow regime interpreted from the interference test between the two wells indicates permeability anisotropy, which may have caused the ETB. Geophysical data interpretations indicate that these fractures correspond to a coupled fault damage zone and a fracture corridor. Finally, we present a fit-for-purpose 2D discrete fracture network model utilizing the PTA results to match our analytically calibrated model. Our study offers a potential hydraulic explanation to the cause of the ETB highlighting the importance of integrating multi-scale/disciplinary data sets to improve the reliability of dynamic reservoir models, based on which, economic-related decisions are made.

Application of well testing technology in YT1 condensate gas well

YT1 is an offshore condensate gas well. During gas testing, well testing is carried out to determine the productivity of the well. The productivity equation is established by modified isochronal well testing. The flow pressure change trend with production under different working systems is compared with the dew point pressure of the gas reservoir under the condition of retrograde condensation to determine the reasonable production differential pressure to avoid the abnormality of productivity equation and calculate the open flow and the reasonable working system. Formation parameters are calculated such as formation pressure, skin factor, effective permeability, flow coefficient, and test radius through pressure build-up test while reservoir type, boundary, and dynamically controlled reserves are determined. According to the analysis results of productivity and reserves, considering the investment cost of offshore gas reservoir development, storage, and transportation, we can comprehensively evaluate the economic rationality of YT1 well construction and production, providing reference experience for improving the benefits construction and production level of the offshore condensate gas reservoir.

Fatigue of short carbon fiber reinforced PEEK under compression: Influence of the load ratio and predictions from heat buildup measurements

AbstractFew works investigate the fatigue of short fiber reinforced thermoplastics under cyclic compression. Furthermore, the heat buildup approach to quickly predict the fatigue lifetime of these materials has not yet been investigated for compression–compression loadings. This paper first describes an experimental protocol to perform well‐controlled cyclic compression tests without anti‐buckling device that may induced bias. The uniaxiality of the global loading is checked during the test based on kinematic and thermoelastic coupling field measurements. Then, the paper compares the results from fatigue and heat buildup tests performed on polyetheretherketone reinforced with 30 wt% of short carbon fibers for several load ratios. It is shown that the fatigue lifetime is higher in compression than in tension and depends on the compression load ratio. The heat buildup approach appears to be relevant to quickly predict the fatigue lifetime of the material for the different loading ratios studied, including compression–compression.

Application of Pressure Transient Analysis in Highly Deviated Reservoir

Conventional pressure transient analysis (PTA) alone may not be a reliable scientific tool for safe oilfield operations and reservoir development, according to earlier studies. The pressure responses were plotted using a skilled simulator in this study to examine the application of PTA and produce an exhaustive analysis. The Nelson oilfield, which is in the UK's North Sea, specifically addressed reservoir characterization and field development in a highly deviated well. The work also used sensitivity analysis and log-log diagnostic plotting to create a model that best matched a short pressure build-up (PBU) test. As a result, reservoir characteristics like permeability, porosity, and reservoir height were modeled, computed, and analyzed alongside wellbore characteristics. For various wells in the Nelson field, averages of core logs, seismic data, and wireline logs were taken to verify the accuracy of these models. Reservoir characterization was accomplished using PTA in conjunction with field data, which improved pre-existing macro and micro datasets. The use of a simulator and such additional data undoubtedly helped to improve field development strategies as well.

A Method for Determination of Rock Fabric Number from Well Logs in Unconventional Tight Oil Carbonates

Summary This paper develops a method for estimation of rock fabric number (RFN) from well logs in unconventional tight oil carbonates with permeability less than 0.1 md. The objective is to investigate the oil potential of a Middle Cretaceous tight carbonate in Mexico. The development of a method for these conditions is challenging as the current approach developed by Lucia (1983) has been explained for carbonates with permeability more than 0.1 md. Core data and drill cuttings available for this study are limited but provide important insights for the log interpretation and for identifying the presence of grainstone, packstone, and wackstone rocks in the unconventional tight carbonate under consideration. A crossplot of RFN vs. rp35 (pore throat radius at 35% cumulative pore volume) permits delimiting intervals with good production potential that are supported by well testing data. Information for the analysis of the Mexican carbonate comes from well logs of nine wells and two re-entry wells, four buildup tests, and a limited amount of core and drill cuttings information. All data were provided by a petroleum company and have been used, for transparency, without any modifications. An unconventional tight carbonate as defined in this paper has a permeability smaller than 0.1 md. The unconventional tight oil carbonate reservoir considered in this study includes 95% of data with permeabilities smaller than 0.1 md and only 5% with permeabilities larger than 0.1 md. The method introduced by Lucia (1983) and Jennings and Lucia (2003) for determining RFN is powerful, but they explained it only for permeabilities larger than 0.1 md, thus the need for a methodology that allows estimating from well logs the presence of grainstone, packstone, and/or wackstone in unconventional tight carbonate reservoirs with permeabilities smaller than 0.1 md. Results indicate that the RFN provides a useful approach for distinguishing grainstone, packstone, and wackstone rocks in unconventional tight carbonate reservoirs. Furthermore, rock fabric can be linked with Pickett plots to provide an integrated quantitative evaluation of RFN, porosity, water saturation, permeability, pore throat radius, and capillary pressure. This integration indicates that there is good oil potential in the Middle Cretaceous unconventional tight carbonate in Mexico.

Remediation of Oil Production by Matrix Acidizing Method on an Oil Well

The remediation oil production by matrix acidizing method on the well named "X" (for confidential reasons) is scrutinized in this paper. Initial production of 1150 bpd, production index of 2.8 STB/Psi/d and permeability of 150md, in 2018 two years down the lane this dropped to 450 bpd, production index 0.7 STB/Psi/d. The declined observed on the production index is trouble shouted and after elimination of (no completion damage/perforation damage), the skin is calculated by carrying out a well test (build-up test) whose extrapolation in excel over times gave us a skin of 40.The reservoir heterogeneity, containing >20% of feldspar, carbonates and paraffin’s guided thematrix acidizing design and treatment proposition to remedy this problem. A positive displacement pump (HT400), boosted by a centrifugal pump were used to pump the acid treatment through high pressure treating line downhole. Halliburton insite for stimulation the (IFS) software monitored treating pressure and surface flow rate, keeping injection rate below fracturing pressure. PipeSim software is used to run the nodal analysis before and after treatment this helped to forecast optimal production rates and pressure after treatments. Matrix acidizing method applied on the well X increased the production to 850 bpd with production index of 2 STD/psi/d, skin - 1.5. The economic benefit to the company stood at (profit oil 21,699,500 USD.) over a two years period of production. Meanwhile uncertainties in demand and supply of crude oil at the international market cause constant fluctuation in oil prices, this should be strongly considered upon execution of this project. Overall applications of this acidizing treatment can be carried out on reservoirs with similar mineralogy. HCl/HF blend dissolves sandstone, mud stone and calcite minerals thus reservoir porosity and permeability can be enhanced in regions extending several meters around the injection well.

Well Performance Following Matrix Acidizing Treatment: Case Study of the Mi4 Unit in Ahdeb Oil Field

The productivity of oil wells may be improved by determining the value of enhancing well productivity and the likely reasons or sources of formation damage after the well has been recognized as underperforming. Oil well productivity may be improved, but the economics of this gradual improvement may be compromised. It is important to analyze the influence of the skin effect on the recovery of the reserve. The acid treatment evaluated for the well AD-12, primarily for the zone Mi4; using a license of Stimpro Stimulation Software to validate the experimental work to the field scale, this software is considered the most comprehensive instrument for planning and monitoring matrix acid treatments and utilizing actual data to provide a far better knowledge of the well's reaction, with methods that represent the reality of what is happening in the reservoir before, during, and after matrix acid treatments, through the post-treatment skin factor, which is the most frequently utilized statistic for analyzing stimulation treatments and relies on the geometry of the wormholed zone. Referring to the previous buildup tests for Ad-12, the skin value of -3.97 is approximately identical to or slightly larger than the skin value estimated by the acid treatment simulation using Stimpro. Moreover, when the simulator was performed, the invading fluid revealed two distinct depths of investigation inside the treated zone. While the fluid invasion in the bottom area has invaded deeply at a distance of 95 inches despite the top layer wormhole penetrating to a depth of 32 inches.

Analysis of Multiple Flow/Buildup Tests Including a 5-Year Buildup: Case Study of an Australian Shale Gas Well

Summary Long-term (multiyear) buildup tests conducted for multifractured horizontal wells (MFHWs) completed in shale reservoirs offer the unique opportunity to study and analyze flow-regimes sequences that are not commonly observed with typical buildup test periods. In this study, two buildup periods (including a rarely observed, nearly 5-year buildup), and the preceding extended flow tests, were analyzed for an MFHW completed in an Australian shale gas reservoir within the Beetaloo Basin. The objectives of the analyses were to (a) identify the sequence of flow regimes observed for each test (flow/buildup, F/BU) period; (b) extract estimates of reservoir permeability and hydraulic fracture properties; and (c) study the evolution of these properties with each subsequent test. An MFHW, the Amungee NW-1H, completed in the Velkerri B shale in Australia, was analyzed. Due to a casing deformation and inability to mill out plugs beyond this, most of the flow contribution was from the heel stages of the well. The first F/BU period was conducted from 2016 to 2021 (a nearly 5-year buildup), while the second F/BU was initiated in 2021 (buildup is currently continuing). The extended (>1 month) production tests (EPTs) preceding the buildups were analyzed using rate-transient analysis (RTA) methods [flow-regime identification/straightline /type curve analysis (TCA)] modified for shale gas properties (e.g., desorption), while the buildups were analyzed using classic pressure-transient analysis (PTA) methods. The first (~5-year) buildup period (BU 1) revealed a sequence of bilinear-linear-elliptical-pseudoradial flow followed by a second linear flow period. The first two flow regimes are interpreted to be associated with interfracture flow, while the latter is assumed to correspond to linear flow to the well. Elliptical/radial flow around fractures is rationalized to occur due to interpreted relatively short fracture half-lengths (corresponding to the high-conductivity portion of the fractures). Permeability estimates are in good agreement with diagnostic fracture injection test (DFIT) analysis. Flow-regime interpretations for the other test periods (EPTs 1 and 2, BU 2) are largely consistent, although EPT 1 flow-regime interpretation was challenged by noisy data. Permeability values derived from EPTs 1 and 2 are smaller than from buildup tests, suggesting stress sensitivity caused by drawdown. Properties derived from the analysis of BU 1 and 2 are in good agreement, suggesting that any effects caused by stress sensitivity of reservoir parameters are largely reversible. Permeability derived from all tests are much larger than those obtained from laboratory data, leading to the interpretation that natural fractures are elevating system permeability. Fracture half-lengths are also much shorter than those typically reported for MFHWs. The mostly “textbook” quality well test data obtained for this field example, combined with the length of the test periods, resulted in one of the most complete flow-regime sequences observed for an MFHW completed in a shale gas reservoir. The existence of a radial flow period observed for all test periods (interpreted to be interfracture radial flow) allows for confident estimates of reservoir permeability/skin and their evolution with each subsequent test, which is rarely reported. The radial-flow-derived permeability, combined with early linear flow analysis, also allowed fracture half-length to be estimated for all tests. This case study adds significantly to our understanding of shale gas reservoir characteristics and flow-regime sequences associated with MFHWs.

Unlocking the Potential of Acid Stimulation in Volcanic Rocks: A Successful Case with Integrated Analysis in Minami-Nagaoka Gas Field, Japan

Summary Acid stimulation of volcanic formations is rarely documented in the literature. A recent study however suggested its potential effectiveness through a comprehensive laboratory/modeling analysis and documented substantial permeability enhancement by dissolution of carbonate-cemented fractures in the near-wellbore area to create wormhole-like high-permeability channels. The study also presented a brief description of successful field execution, although operational details and analysis of results were not presented. This work presents in detail the field case of a multistage acidizing treatment in the Minami-Nagaoka gas field, a volcanic reservoir, and demonstrates the effectiveness of acid stimulation with 10% formic acid for productivity enhancement. The selection of a target well relies on the abundance of cemented fractures along a well. The operational design considers multiple field/well characteristics, such as low permeability; long, perforated intervals; and high-temperature conditions. Effectiveness of acid stimulation is evaluated comprehensively and justified by the integration of real-time stimulation diagnostics using distributed temperature sensing (DTS), real-time surveillance of bottomhole key parameters obtained thanks to coiled-tubing (CT) fiber-optic downhole telemetry, pre-/post-acidizing pressure buildup (PBU) tests, and production logging tool (PLT) surveys. A multistage acidizing operation was executed, after completion of a step-rate test during which a pre-acidizing DTS survey was acquired. Eight stages of 10% formic acid injection and seven stages of degradable particulate diverter placement were pumped, followed by brine displacement and a post-acidizing DTS acquisition. In all the stages, acid injection decreased the bottomhole pressure while the use of diverter increased it (by hundreds of psi), thus indicating success in acid stimulation and diversion, respectively. The stimulation almost doubled the gas flow rate just after the operation, and 10 months after the operation, the gas rate is still 1.5 times higher than before intervening. Pre-/post-acidizing PBU tests suggested a substantial reduction of the skin from 1.50 to −1.91. DTS surveying identified one major and three minor fluid-intake intervals through stimulation/diversion, and integrated analysis with PLTs revealed that the substantial improvement in gas rate was primarily coming from a narrow zone located within the major intake interval, where resistive fractures are abundant. The current case demonstrates the effectiveness of 10% formic acid for the stimulation of rocks with carbonate-cemented fractures, which was also proposed by the former study. It also shows that there is still room for further optimization in the operational design. This paper provides insights on acid stimulation in volcanic rocks and highlights its effectiveness through the analysis of a series of data sets. Readers may obtain knowledge on acidizing design, the evaluation of its effectiveness, and the interpretation of results, with lessons learned through job execution. The study will also serve as a reference to evaluate the potential of acid stimulation for the development of other volcanic reservoirs.

Influences of Well Test Techniques and Uncertainty in Petrophysics on Well Test Results

In the present study, well logs and well test data of both conventional build-up tests and Mini-DST from different oil and gas fields are utilized to evaluate the effects of uncertainty in petrophysics and test techniques on well test results. This includes producing wells from the Nile Delta and Western Desert-Egypt together with published results from West Qurna oil field-Iraq. Results indicated that permeability is strongly dependent on petrophysics interpretation, particularly pay thickness, while the radius of investigation is significantly dependent on fluid properties, especially compressibility. The skin factor calculations showed great sensitivity towards the pressure measurements with medium influences on porosity and oil viscosity. The calculations of Mini DST and Build-up test are compared within the uncertainty context for effective permeability, radius of investigation, and skin factor, and the findings are discussed in detail. In all cases, error analysis indicated that well test results and interpretation of conventional build up data are largely stable and may reduce overall uncertainty to 30% of the corresponding Mini-DST results/interpretation. The results of this study not only characterize each input parameter involved in the interpretation of well test data but also confirms the superiority of conventional build-up on Mini-DST techniques.

Fracture network types revealed by well test curves for shale reservoirs in the Sichuan Basin, China

Pressure buildup testing can be used to analyze fracture network characteristics and conduct quantitative interpretation of relevant parameters for shale gas wells, thus providing bases for assessing the well productivity and formulating proper development strategies. This study establishes a new well test interpretation model for fractured horizontal wells based on seepage mechanisms of shale reservoirs and proposes a method for identifying fracturing patterns based on the characteristic slopes of pressure buildup curves and curve combination patterns. The pressure buildup curve patterns are identified to represent three types of shale reservoirs in the Sichuan Basin, namely the moderately deep shale reservoirs with high pressure, deep shale reservoirs with ultra-high pressure, and moderately deep shale reservoirs with normal pressure. Based on this, the relationship between the typical pressure buildup curve patterns and the fracture network types are put forward. Fracturing effects of three types of shale gas reservoir are compared and analyzed. The results show that typical flow patterns of shale reservoirs include bilinear flow in primary and secondary fractures, linear flow in secondary fractures, bilinear flow in secondary fractures and matrix, and linear flow in matrix. The fracture network characteristics can be determined using the characteristic slopes of pressure buildup curves and curve combinations. The linear flow in early secondary fractures is increasingly distinct with an increase in primary fracture conductivity. Moreover, the bilinear flow in secondary fractures and matrix and the subsequent linear flow in the matrix occur as the propping and density of secondary fractures increase. The increase in the burial depth, in-situ stress, and stress difference corresponds to a decrease in the propping of primary fractures that expand along different directions in the shale gas wells in the Sichuan Basin. Four pressure buildup curve patterns exist in the Sichuan Basin and its periphery. The pattern of pressure buildup curves of shale reservoirs in the Yongchuan area can be described as 1/2 → 1/4, indicating limited stimulated reservoir volume, poorly propped secondary fractures, and the forming of primary fractures that extend only to certain directions. The pressure buildup curves of shale reservoirs in the main block of the Fuling area show a pattern of 1/4 → 1/2 or 1/2, indicating greater stimulated reservoir volume, well propped secondary fractures, and the forming of complex fracture networks. The pattern of pressure buildup curves of shale reservoirs in the Pingqiao area is 1/2 → 1/4 → 1/2, indicating a fracturing effect somewhere between that of the Fuling and Yongchuan areas. For reservoirs with normal pressure, it is difficult to determine fracture network characteristics from pressure buildup curves due to insufficient formation energy and limited liquid drainage.

Potential of Fluoride-Containing Zinc Oxide and Copper Oxide Nanocomposites on Dentin Bonding Ability.

Despite recent advances in bonding restorations, which are the basis of restorative dentistry, secondary caries are still able to form. Previously, a novel fluoride-containing zinc and copper (ZCF) nanocomposite was introduced to prevent the formation of caries due to its antibacterial activity. In this study, we studied the impact of ZCF nanoparticles on the adhesive strength of bonding restorations through micro-tensile bond strength (µTBS) testing. The impact of antibacterial and matrix metalloproteinase (MMP) inhibitors on the nanoparticles was also examined. The nanocomposites were prepared using a simple one-step homogeneous co-precipitation method at a low temperature. A self-etch adhesive was applied to 10 extracted caries-free human molars with (test group) and without (control group) the ZCF nanoparticles. This was followed by composite resin build-up and µTBS testing, MMP activity assays, and evaluation of the antibacterial effects. The results showed no significant differences in the µTBS between the ZCF and the control groups. However, the ZCF exhibited a significant inhibitory effect against MMP-2, MMP-8, and MMP-9, in addition to an antibacterial effect on Streptococcus mutans. Therefore, the present study demonstrated that the addition of ZCF nanoparticles to adhesive systems can result in MMP inhibition and antibacterial action while maintaining the mechanical properties of the bonding restorations.

Modular zonal fluid sampling and pressure testing technology for production well

To accurately obtain development dynamic data such as zonal pressure and fluid parameters of each oil layer in the late development stage of a high water-cut old oilfield, a modular zonal sampling and testing technology with the characteristics of modularization, full electronic control and rapidity was proposed and developed. Lab testing and on-site testing was carried out. The modular zonal sampling and testing system is composed of 10 functional modules, namely ground control system, downhole power supply module, drainage pump, electronically controlled anchor, electronically controlled packer, electronically controlled sampler, magnetic positioning sub, terminal sub, adapter cable, and quick connector. Indoor tests have confirmed that the performance parameters of each module meet the design requirements. The downhole function modules of the system can withstand pressures up to 35 MPa and temperatures up to 85 °C. The rubber cylinder of the electronically controlled packer can withstand a pressure difference of more than 10 MPa. The electronically controlled anchor has an anchoring force of greater than 6.9 t, and can be forcibly detached in the event of an accident. The discharge pump has a displacement of 0.8 m3/d and a head of 500 m. The electronically controlled sampler can meet the requirement of taking 500 mL of sample in each of the 3 chambers. Field tests in Jilin Oilfield show that the system can realize rapid isolation and self-check of isolation of a certain production interval downhole, as well as layer-by layer pressure build-up test. The drainage pump can be used to discharge the mixed liquid between the upper and lower packers and near the wellbore to obtain real fluid samples of the tested formation interval. The data obtained give us better understanding on the pay zones in old oilfields, and provide important basis for development plan adjustment, reservoir stimulation, and EOR measures.

CHANGING WELLBORE STORAGE IN GAS WELL TESTING

Extended wellbore storage can be mistakenly interpreted as a reservoir response in gas well testing with surface shut in. This interpretation usually results in false value for permeability, skin and reservoir size and shape. This paper investigates changing wellbore storage in pressure transient testing with surface shut-in in gas well. This study was prompted by the observation, that in gas wells, many of the buildup tests obtained with surface shut-in exhibited complex reservoir model behavior with relatively low skin. The results presented in this paper are based on well test simulation and field data from North Sumatera. This work demonstrates the effect changing wellbore storage on the pressure derivative curve. Knowledge of the expected pressure derivative shape, and duration, will improve the design of buildup tests that will allow enough time for the actual reservoir response to be observed. This will result in a reliable reservoir model and correct estimation of permeability and skin factor.