Perforated Intervals Research Articles

Matrix Acidizing Of Yamama Pay Zones

Yamama formation in southern of Iraq has been studied well, and 25 core samples have been chosen from 7 wells to study their responses to matrix acidizing experiments by different acid solutions. It is found that:1. Solutions of 5% HCl as preflushes and afterflushes are needed in volume depended on cores porosity.2. A solution of 15% HCl with its additives [0.6% A-250 and 0.75% of the solution of Iraqi detergent powder] was the suitable solution for the stimulation of these cores.Previous acid treatments were analyzed and the following techniques were suggested to get the best results:1. Using paccaloni planning- evaluation method to get the best quality control.2. Placing the acid in front – of the perforation interval.3. After completion of acid injection, an immediate opening to flow is necessary.4. Adequate cleaning period would be important after acid job.

Single-Well Modeling Study In Buzurkan Oil Field

Single well modeling technique is considered as an important tool in simulation studies that deal with the near well issues (i.e. water coning, optimum perforation intervals, etc.); or it may be used in the determination of the final acceptability of the entire field model (1). In this study, this technique is adopted to study and characterize one of the producing wells in Buzurkan oil field which is BU-3. The probability of the increase of water production will be tested with different production schemes, because if the well has to produce with certain water rate, the surface facilities have to be designed to be suitable for that rate. Water saturation distribution around the well is also inspected through the history of the well to determine the reason behind water production.
 CMG simulator has been used to perform this study. The results matching are based on the pressure and the produced water cut history and show good match in both cases.
 The model showed that there is a significant increase in water production with increase of oil rate due to water coning.

Simulating a Controlled CO2 Release Experiment in a Shallow Fault Zone in Western Australia

Geological and dynamic modelling studies are routinely performed to design and interpret field test experiments. These studies help with the planning of well location, well operations and monitoring strategies, as well as with a range of different test activities. After the test, the new interpretations of the experiment observations are then integrated with previous knowledge and reconciled with the assumption that was first tested. Often, the results of a test are significantly different from what was anticipated (hence the purpose of testing). In this work, we examine such an example and put in perspective the impact of the first modelling study on the interpretation of the test. The CSIRO In-Situ Laboratory Project (In-Situ Lab) is located at the eastern edge of the South West Hub CCS Flagship project (SW Hub) in Western Australia, which has been identified as a potential area for commercial-scale CO2 storage. A first test at the In-situ Lab has evaluated the ability to monitor and detect unwanted leakage of CO2 from a storage complex in the shallow subsurface. The In-Situ Lab is also collocated within a major fault zone. Prior to a controlled-release test, a numerical simulation study was undertaken to inform the optimal location for a monitoring well, the vertical location of the downhole instrumentation, and to ensure breakthrough of CO2 occurred within the project timeframe. Based on the likely extent of the CO2 plume for an injection volume of 40 tonnes, the observation well ISL OB-1 was located at 7 m from the injection well to maximise the likelihood the CO2 plume would be intersected. The CO2 plume was predicted to migrate vertically for at least 20 m above the injection interval. Due to the resolution of the existing seismic and limited well data, large uncertainty existed regarding the detailed fault zone geometry, and, more specifically, how disaggregation and drag has impacted the contiguity and slope of lithostratigraphic layers within the fault zone. In other words, it was not clear to what extent the relatively low-permeability paleosols would form baffles for the migration of CO2. Also, it was not known whether sub-seismic faults, if present, would act as vertical barriers or conduits to CO2 migration. During a controlled-release test, 38 tonnes of gaseous CO2 were injected in February 2019, and the gas was monitored by a wide range of downhole and surface monitoring technologies. A higher than expected bottomhole pressure was observed. CO2 reached the ISL OB-1 monitoring well after approximately 1.5 days. Observations suggest that the fault zone did not alter the CO2 migration along bedding at the scale and depth of the controlled release experiment. No vertical CO2 migration was detected beyond the perforated injection interval. The injectivity was lower than predicted from core measurements and prior modelling. Also, contrary to prior model predictions, the plume did not migrate vertically across the paleosol overlying the injection interval. Post-injection reservoir simulations calibrated to the observed pressure and CO2 distribution data confirm that (1) a vertical segregation exists just above the injection interval, and (2) local overpressure are due to a combination of wellbore damage, mud invasion at the injection well and, to a lesser extent, reservoir compartmentalisation.

Characterization and sampling of a deep and heterogeneous aquifer – An application to the Paleocene – Eocene aquifer in the Aquitaine basin, France

Groundwater sampling in boreholes has been carried out for decades according to well-established protocols and regulations. An important requirement in this context is the need to purge the borehole prior to any sampling action, the volume of the purge being adapted to the water flow and the regulatory context. Contaminated site investigations have introduced the concept of water column heterogeneity in the screened section of boreholes, which also occurs in some uncontaminated boreholes or in long-screened boreholes. Specific guidelines and practices were thus introduced, in particular the concept of discrete sampling. This type of sampling can be advantageously used in deep boreholes, provided that there is some renewal of water at the screens or the perforated intervals. The present study aims to take a step forward in the characterization of deep boreholes set up in the Aquitaine basin in France, by defining a protocol for relatively short boreholes (depth < 170 m) and applying it to much deeper boreholes, formerly drilled for oil and gas exploration (sampling up to 1035 m deep). Acquisitions were performed to better characterize water chemistry, including some isotope considerations. They were based on physico-chemical logging and endoscopic inspections where technically possible. After a review of the information provided by the investigations on the characterization of the Paleocene – Eocene aquifer in southwestern France, a methodology is proposed to make sampling in deep boreholes with low-yield more reliable, by combining the abstraction of a reduced water volume and the use of a downhole sampling system.

Use of Inline Spinner for Determination of Zonal Flow Rates in Vertical and Moderately Deviated Wells

Summary Accurate zonal flow rate determination is necessary for better reservoir behavior understanding and for making important decisions that can improve well productivity. Knowledge of the capabilities of different reservoir zones in the same well also has significant importance in reservoir performance monitoring and selection of perforation intervals in development wells. Conventional production log analysis techniques can usually yield good results only if the fullbore spinner readings are reliable. However, the fullbore spinner measurement may not be available in some wells. Examples include cases in which the fullbore spinner cannot access the well due to mechanical obstruction, or when the casing is not clean enough, causing potential plugging of fullbore spinner blades. In these situations, the fullbore flow-rate readings may not be available or at least unclear or confusing, which may lead to incorrect decisions. In many of these situations, inline spinner (ILS) data may be readily available. The ILS is often used for qualitative interpretation (i.e., determining which zones are producing), but there is not a specific method to use the ILS for a quantitative solution in the absence of surface measurements of rates. In this paper, we introduce a new method to calculate the volumetric zonal flow rate using ILS data with high accuracy. Approximately 40 oil wells are used to develop an empirical correlation to compute zonal flow rates from ILS data in casing strings. The new method was used to quantitatively interpret eight oil wells for validation. In these wells, fullbore and ILS data were significantly different. The new method for interpretation of ILS data provided results consistent with surface production tests and led to decisions that contributed to increasing production rates.

Brittleness modeling selects optimum stimulation zone in shaly source rocks in the Whangai Formation, New Zealand

Within New Zealand, the East Coast Basin represents the primary shale oil and gas play in which the Whangai Formation is widespread. This formation is oil and gas prone and prevalent throughout a large area of the East Coast Basin and is typically composed of the Upper Calcareous, Porangahau, and Rakauroa Members. The primary goal of this study was to develop an integrated methodology to define the best stimulation intervals in the formation. To do this, we evaluated four different definitions of the brittleness index for the Rakauroa Member, the only member drilled in the three study wells. A Python-based automated process was specifically developed for this purpose and uses four indexes: elastic parameters, internal friction coefficient, mineralogy, and total organic carbon content. Through this process, these four indexes were analytically combined to select intervals with the highest brittleness values and identify the optimum stimulation interval and most desirable perforation intervals in the pay zone. Our results show that the Whangai Formation contains 25% clay (and reaching up to 70% clay content in some intervals) and a maximum organic matter content of 2.54%. The geomechanical model indicates a uniform distribution of high pore pressure across the entire reservoir section. The interval between 1497 and 1750 m in the Opoutama-1 well located in the Coastal block presents high combined brittleness indexes, indicating excellent characteristics from a stimulation standpoint.

Improvement of oil field development using enhanced oil recovery methods

Purpose. To develop a technology to increase the oil recovery of formations using injection of polymer compositions. Methodology. For this study, practical methods were used such as enhanced oil recovery using stimulating technologies, technology using polymer systems based on a water-soluble polymer acrylamide, and emulsion-polymer technology. To achieve the conformance control, which was a prerequisite for testing, a thorough selection of wells was carried out, as well as an analysis of their hydrodynamic connection. Findings. As a result of using the method for limiting water inflows in the development of oil-bearing formations, redistribution of filtration channels, and a decrease in the production of fossil water as well as stabilisation of water cut were achieved. Originality. The scientific novelty of the study is the withdrawal of wells that are able to redistribute the volume of water injection at perforation intervals. Increased sweep efficiency and pressure at the wellhead at the beginning and at the end of the conformance control indicate a decrease in the conductivity of high-permeability formation intervals. Practical value. Application of the proposed technology for limiting water inflows will make it possible to develop low-permeability interlayers with filtration flows. The wells brought to a stable production rate during the study will ensure a decrease in formation water production and the water cut of the produced products, as well as stabilisation of the water cut over a certain period.

A (not so) shallow controlled CO2 release experiment in a fault zone

The CSIRO In-Situ Laboratory Project (ISL) is located in Western Australia and has two main objectives related to monitoring leaks from a CO2 storage complex by controlled-release experiments: 1) improving the monitorability of gaseous CO2 accumulations at intermediate depth, and 2) assessing the impact of faults on CO2 migration. A first test at the In-situ Lab has evaluated the ability to monitor and detect unwanted leakage of CO2 from a storage complex in a major fault zone. The ISL consists of three instrumented wells up to 400 m deep: 1) Harvey-2 used primarily for gaseous CO2 injection, 2) ISL OB-1, a fibreglass geophysical monitoring well with behind-casing instrumentation, and 3) a shallow (27 m) groundwater well for fluid sampling. A controlled-release test injected 38 tonnes of CO2 between 336-342 m depth in February 2019, and the gas was monitored by a wide range of downhole and surface monitoring technologies. CO2 reached the ISL OB-1 monitoring well (7 m away) after approximately 1.5 days and an injection volume of 5 tonnes. Evidence of arrival was determined by distributed temperature sensing and the CO2 plume was detected also by borehole seismic after injection of as little as 7 tonnes. Observations suggest that the fault zone did not alter the CO2 migration along bedding at the scale and depth of the experiment. No vertical CO2 migration was detected beyond the perforated injection interval; no notable changes were observed in groundwater quality or soil gas chemistry during and post injection. The early detection of significantly less than 38 tonnes of CO2 injected into the shallow subsurface demonstrates rapid and sensitive monitorability of potential leaks in the overburden of a commercial-scale storage project, prior to reaching shallow groundwater, soil zones or the atmosphere. The ISL is a unique and enduring research facility at which monitoring technologies will be further developed and tested for increasing public and regulator confidence in the ability to detect potential CO2 leakage at shallow to intermediate depth.

A New Method to Determine the Lower Limit of Reservoir Physical Properties—Corrected Minimum Flow Pore-throat Radius Method

The lower limit of reservoir physical properties is an important parameter for identifying reservoirs and determining effective thickness in reserves evaluation, and is also an important basis for selecting perforated test intervals in oilfield exploration and development. There are many methods to determine the lower limit of reservoir physical properties, and the minimum flow pore throat radius method is one of the commonly used methods. The method uses 0.1μm as the minimum flow pore-throat radius, and uses this to calibrate the lower limit of reservoir physical properties. However, according to the water film theory, the minimum radius of the reservoir's flowing pore throat is not a definite value, but varies with the displacement dynamics. Therefore, there is no exact basis for using 0.1μm as the minimum flow pore-throat radius, so it needs to be corrected. To this end, a new method for determining the lower limit of reservoir physical properties—the corrected minimum flow pore-throat radius method is proposed. The correction method comprehensively considers the factors of oil and gas accumulation dynamics, and determines the lower limit of reservoir physical properties by obtaining the minimum flow pore-throat radius value suitable for oil and gas accumulation dynamics. A case study of Chang 63 reservoir in A Oilfield shows that the minimum flow pore radius of oil and gas determined by the correction method is 0.08 μm, and the lower limit of reservoir physical properties (porosity 9.1%, permeability 0.117 × 10-3 μm2). The traditional method has a minimum flow pore-throat radius of 0.1 μm and a lower limit of reservoir physical properties (porosity of 9.8% and permeability of 0.133 × 10-3 μm2). Due to full consideration of the impact of oil and gas accumulation dynamics, the minimum flow pore-throat radius determined by the correction method is more reliable than the traditional method, and the lower limit of the reservoir physical property calibrated by it has practical significance.

A meta-analysis of colonic stenting in obstructive left colon cancer

Background/Introduction: Colonic self-expanding metallic stents have been long been employed for various indications for malignant large bowel obstruction. However, there remains controversy in the impact of perforation rates and interval between stenting and surgery.

Pumpdown Diagnostics for Plug-and-Perf Treatments

SummaryIn this paper, we introduce pumpdown diagnostics, an economical process in which cement sheath integrity, perforation cluster spacing, and fracturing (frac) plug integrity can be assessed for every fracturing stage, potentially leading to improvements in stimulation, completion, cementing, and drilling practices. It is based on analyzing wellbore pressure responses occurring at key segments of the wireline pumpdown and perforating operation and correlating the results among multiple fracturing stages and wells in a field or play. A special requirement is that the ball check is inserted in the frac plug and pumped to seat prior to performing perforating operations. A complementary benefit of this process is that selectively establishing injectivity in the most distant perforation cluster can be used to establish inhibited hydrochloric (HCl) acid coverage across all perforation intervals for uniform reduction in near-wellbore tortuosity.Reviews of pumpdown diagnostics field cases from several unconventional plays provide the following insights. Pumpdown diagnostics are time efficient and economical, requiring approximately 15 minutes per fracturing stage. Evaluating communication to the previous fracturing stage can serve as a key performance indicator for treatment control or cement sheath integrity. Pumpdown diagnostic results can be more reliable than cement bond log evaluation, and stage isolation characteristics can be strongly affected by cluster spacing.

CFD simulation design and optimization of a novel zigzag wave-plate mist eliminator with perforated plate

A zigzag wave-plate mist eliminator with an internally improved structure of perforated plate was proposed in this work, which applied in particle removal process for lime-stone wet flue desulfurization (WFGD) system. Its performance was evaluated by Computational Fluid Dynamics (CFD) methods with three criteria, overall collection efficiency, system pressure drop, and impact factor. The realizable k-ε turbulence model and Eulerian-Lagrangian methodology were adopted to describe the motion of the continuous phase and dispersed phase. The CFD results showed that the main factors affecting the performance of perforated plate mist eliminator are the number of perforated plates N, the perforated plate interval spacing I, the hole diameter d1, the distance between two holes d2, porosity ε, installation angle α, and the height of the perforated plate h. Compared with the wave-plate mist eliminator with porous foam layers, the mist eliminator with perforated plate is found to have better performance in particle removal. The overall particle collection efficiency is increased by more than 2.3%, the pressure drop is reduced by more than 27.4% while the porosity of the perforated plate is small. When ε is large, the particle collection efficiency of the porous plate with large porosity decreased by 0.3–1.2%, the pressure drop was reduced by more than 34.7%. Besides, it has a simple structure and can be processed by integrated technology. All these advantages make the perforated plate mist eliminator a promising candidate for fine particle removal in the WFGD system.

A predictive protocol to obtain maximum water-free oil production rate for perforated vertical wells

Producing an oilfield in a cost-effective way depends on how long water production could be delayed in the reservoir. Many flow mechanisms, correlations, and methods to calculate maximum water-free oil production rate have been published, However, those methods have generally failed to not consider the skin effect which affects the flow into the wellbore. In this paper, the semi-analytical perforation skin model as presented by Karakas and Tariq is incorporated into the Meyer and Garder correlation for critical oil rate from a perforated vertical well interval to obtain the maximum water-free oil production rate and optimal perforation parameters. The resulting coupled computational model is used to determine the sensitivity of the maximum water-free oil production rate to wellbore perforation parameters. Whilst an increase in perforation length and decrease in spacing between perforation increase the critical flow rate, an increase in perforation radius did not translate to higher productivity. The optimal perforation angles are 45° and 60°, however, for the data used in this work the maximum water-free oil rate of 23.2 std/d was obtained at 45° of phasing angle, 1 in of spacing between perforation, 0.36 in of perforation radius and 48 in of perforation length. Thus, the perforation strategy can be optimized prior to drilling and completion operations to improve productivity using the computational model presented in this work.

Reduction of well stimulation period after hydraulic fracturing

This article discusses the problems associated with the removal of proppant, mechanical particles of the rock and undecomposed fluid from the hydraulic fracture into the well. The necessity of developing a device for washing the perforation interval has been identified and justified. It is shown that hardened and viscoelastic gel particles fall into perforations and adhere to the walls of channels and wells. Subsequently, these zones of gel deposition reduce permeability in perforation channels. The author has developed the design of a device for decolmation (declogging), which reduces the time for well development after hydraulic fracturing. To increase the productivity of the considered wells, it is necessary to flush them with the presented device in the mode of maximum approximation to deposits. To carry particles better to the surface, it is proposed to use foam systems generated by the jet pump, which is described in this article.

Natural Fractures in Carbonate Basement Reservoirs of the Jizhong Sub-Basin, Bohai Bay Basin, China: Key Aspects Favoring Oil Production

Analysis of natural fractures is essential for understanding the heterogeneity of basement reservoirs with carbonate rocks since natural fractures significantly control key attributes such as porosity and permeability. Based on the observations and analyses of outcrops, cores, borehole image logs, and thin sections from the Mesoproterozoic to Lower Paleozoic in the Jizhong Sub-Basin, natural fractures are found to be abundant in genetic types (tectonic, pressure-solution, and dissolution) in these reservoirs. Tectonic fractures are dominant in such reservoirs, and lithology, mechanical stratigraphy, and faults are major influencing factors for the development of fractures. Dolostones with higher dolomite content are more likely to have tectonic fractures than limestones with higher calcite content. Most tectonic fractures are developed inside mechanical units and terminate at the unit interface at nearly perpendicular or high angles. Also, where a thinner mechanical unit is observed, tectonic fractures are more frequent with a small height. Furthermore, the dominant direction of tectonic fractures is sub-parallel to the fault direction or oblique at a small angle. In addition, integrating diverse characteristics of opening-mode fractures and well-testing data with oil production shows that, in perforated intervals where dolostone and limestone are interstratified or dolostone is the main lithologic composition, fractures are developed well, and the oil production is higher. Moreover, fractures with a larger dip angle have bigger apertures and contribute more to oil production. Collectively, this investigation provides a future reference for understanding the importance of natural fractures and their impact on oil production in the carbonate basement reservoirs.

Productivity Improvement by Reperforation of Multistage-Fractured Wells in High-Pressure/High-Temperature Tight Gas Reservoirs: A Case History

SummaryProductivity of multistage-fractured gas wells is possibly degraded by conductivity impairments and non-Darcy flow during long-term production. Such degradations are pronounced by flow convergence to short perforated intervals, while it is challenging to identify degraded stages for remediation. Moreover, remedial actions can be expensive under a high-pressure/high-temperature (HP/HT) environment. A field case demonstrates successful application of reperforation as a cost-effective way to mitigate the flow convergence by prioritizing targets with multirate production-logging (PL) results.This work presents theoretical investigations using numerical simulations and field execution of reperforation for a well with six-stage fracturing treatments in a HP/HT volcanic gas reservoir onshore Japan. Apparent conductivity reduction was suspected during more than 15 years of production, and it was pronounced by non-Darcy flow effects associated with flow convergence to short perforated intervals. Multirate PL was used to identify impaired stages by quantifying the inflow-performance relationship (IPR) of each stage under transient flow-after-flow (FAF) testing. The impaired stages were reperforated, adding perforation intervals with wireline-conveyed perforators. Pressure-buildup (PBU) tests before and after the job and post-job PL were used to validate productivity improvements.Target zones for reperforations were identified and prioritized with results of the multirate PL conducted. The stage IPRs were drawn, and relatively large non-Darcy effects were identified in three stages by shapes of the IPRs and/or decreasing inflow contributions as the surface rate increased. Also, a temperature log showed steep temperature change at the bottom of the fourth stage; the fracture might propagate below the perforated interval. Ranges of production increment were estimated using a numerical model calibrated against the estimated stage IPRs. The estimated increment was in the range of 15 to 30% with the planned reperforation program, while its magnitude depended on the connection between new perforations and existing fractures. Afterward, the reperforation job was performed and the gas rate was confirmed to be increased by 26% with the same wellhead pressure after 1 month of production. The post-job PL was conducted 3 months after the reperforation. The well IPR was improved, implying reduction of the non-Darcy effects. Results of PBU tests also indicated reduction of skin factor. The stage IPRs were redrawn with the post-job PL, and they suggested clear improvements in two stages where screenout occurred during fracturing treatments and a stage where significant non-Darcy effect was suspected.The workflow and strategy in this paper can be applied for productivity restoration in a cost-effective way to multistage-fractured gas wells with short perforated intervals and impaired apparent conductivity during long-term production. Especially, the interpreted results suggested effectiveness of the proposed approach for productivity improvement in stages where screenout occurs during fracturing treatments. Moreover, lessons learned on the importance of careful test designs for PL were discussed because they are keys for success.

Productivity of hydraulic fractures with heterogeneous proppant placement and acid etched walls

Production estimation for hydraulic fractures with heterogeneous proppant placement is not straightforward and requires numerical solution. Contrasts in hydraulic conductivity are intentionally created by channel fracturing, when proppants are injected by pulses in stages, or as a result of fracture wall etching by acids. In both types of fracturing treatment, a connected network of open channels is expected to form within a fracture. The channels not only create primary pathways for producing fluids, they are also very compliant regions that are subject to closure and pinching under large effective stresses. We develop a numerical model of hydraulic fracture productivity considering heterogeneous distribution of conductivity and channels. For various geometries of proppant pillars and etched walls, reservoir properties, and size of perforation intervals, we calculate total production rates from a hydraulic fracture as a function of pressure drawdown. We evaluate other productivity indicators such as skin factor and effective dimensionless conductivity traditionally used by field engineers. We show that our numerical solution agrees with exact solutions of several problems with rectangular and circular fracture geometry, with uniform or stepwise conductivity profile. The presented model can be used for accurate evaluation of pressure-dependent well productivity after channel fracturing and acid fracture treatments. An important application of our model is the optimization of the pressure drawdown schedule to reach the maximum production rates in the created fractures, which is often ignored by oilfield companies.

A comprehensive method for determining net pay in exploration/development wells

Net pay is the key parameter in reserve estimation, reservoir modeling, production planning, well test interpretation and selection of perforation intervals. Net pay determination is always mixed with some uncertainty due to the lack of data, low level of knowledge about the reservoir characteristics and complicated fluid-rock interactions. Conventionally, a permeability cutoff is selected and the net pay is defined as the part of the reservoir that has permeability greater than the cutoff value. The main problem arising from the use of permeability cutoff is that its value depends on many factors like type of reservoir fluid, well completion method, economical constraints, oil price and surface facilities for the treatment of the produced fluids. The proposed methodology of the present study is based on the construction of a hydrocarbon rate profile in the whole or the selected reservoir interval using the core and petrophysical data. Considering all the factors mentioned above, a hydrocarbon rate limitation combined with economic-profitability condition is defined to discriminate productive zones from nonproductive zones and consequently the Net-To-Gross ratio (NTG) is calculated. This novel method has been applied to four different carbonate reservoirs in Iran and showed a perfect match with the production data. The reservoirs are selected in such a way to cover different lithology, fluid types and well completions. The results obviously indicate how all available data should be integrated to determine net pay and that the proposed approach is a straightforward and powerful tool in selecting the proper reservoir interval to perform production testing in exploration/development wells.

The use of flowback data for estimating dynamic fracture volume and its correlation with completion-design parameters: Eagle Ford cases

Hydraulic fracturing combined with horizontal drilling is the key to unlocking vast unconventional reservoirs. However, understanding the relationship between completion-design parameters (CDPs) and fracturing efficiency remains challenging. The objective of this paper is analyzing flowback data to 1) evaluate the change in effective fracture volume (Vef), and 2) investigate the existence of correlations between CDPs and Vef. We analyze flowback data and CDPs of 22 gas and oil wells completed in the Eagle Ford formation. First, we estimate ultimate water recovery and initial effective fracture volume (Vefi) using harmonic-decline (HD) model. Second, we estimate the loss in Vef (Vloss) during flowback using a new iterative approach that accounts for dynamic fracture porosity and compressibility. Third, we introduce a new parameter to characterize fracture closure rate (FCR) during flowback. FCR represents how fast Vef shrinks during flowback. Then, we present a dimensionless type curve to evaluate FCR and investigate its correlation with CDPs. Finally, we conduct a multivariate analysis to correlate CDPs with Vefi and FCR.The developed correlation between Vefi and CDPs shows that the gross perforated interval (GPI) has the most significant effect on Vefi. The proposed correlation between FCR and CDPs demonstrates the significant effect of proppant concentration on fracture closure during flowback.

A Comprehensive Method for Diverter-Performance Evaluation during Stimulation of Long-Interval Heterogeneous Reservoirs: A Case Study

Summary The accomplishment of matrix stimulation in highly contrasted permeability reservoirs is critically dependent on diversion. Consequently, assessment of the diversion performance is a key to determine the success of stimulation. However, there are still doubts on the evaluation of diversion effectiveness, especially in long-interval heterogeneous reservoirs. When a diverter enters the formation, a hump in the surface pressure curve is usually expected. Then, it can be interpreted as supporting evidence for diversion. However, this is a simplification of the fluid-diversion process. It could be possible that a hump is not observed during a diversion stage, although it is effective. Therefore, what should be done? To overcome this challenge, we propose a more-accurate diversion-evaluation method and validate it with available matrix-stimulation data. Three methods were introduced in the literature to evaluate matrix-stimulation performance: Paccaloni, Prouvost, and Chan [inverse injectivity (i.e., Iinv)] methods (Prouvost and Economides 1987, 1989; Paccaloni and Tambini 1993; Chan et al. 2003). The latter is easy to use and accurate, which accounts for transient flow effects. In this paper, the inverse injectivity method is modified and validated with the real data of two matrix-acidizing operations in a gas/condensate field. The performed modifications in the evaluation process include a bottomhole-pressure-calculation procedure, which is validated with available drillstem-test (DST) matrix-stimulation data, and simultaneous utilization of Iinv and its derivative plot. Humps in the Iinv plot, which can be interpreted as diverter performance, are sometimes so small that it is difficult to distinguish the diverter effect from possible noises in the data. Here, the derivative plot of Iinv is used as a complementary tool to improve the interpretation process. Results indicate that for both wells in this study, the modified Iinv shows clear humps when diverters enter the reservoir. In addition, exactly when Iinv builds up, a sign change in the derivative plot is observed. This shows that these two parameters have a confirming behavior. Finally, pre/post-stimulation production data were used to practically prove the calculations behind the method. Here, the target of design was to divert stimulation fluids to the low-permeability bottom layer because it was both a high-pressure and high-hydrocarbon reserve. Per production-logging data, the majority of production before stimulation was originated from a sublayer. In the first operation, with the rare appearance of surface pressure humps, Iinv and its derivative showed satisfactory outputs of diversion occurrence. After stimulation, production logging confirmed the diversion of flow and nearly uniform production across the targeted interval. Hence, this indicates that the modified method accurately demonstrates the performance of the diversion system in acidizing operations with long perforated intervals, even if there is a rare distinct pressure hump in the surface. Therefore, this could be adapted either for cases where there is no access to the production logging or for the cases in which the hump in surface pressure is not observed.