Perforation Strategy Research Articles

Identifying perforation locations for hydraulic fracturing treatment in deep and tight sandstone gas reservoirs

Fracture initiation has been a challenging issue for fracturing deep and tight gas reservoirs, which generally requires a high breakdown pressure for hydraulic fracturing treatment. In this situation, fluid injections frequently have to terminate at the very beginning. Toward predicting and solving this issue, a novel fracturing system for deep and tight sandstone gas reservoirs was developed. The key components of the fracturing system and some criterion will be introduced, which can be used to optimize the ideal perforation locations along the landing part and select the right perforation strategy accordingly. The main components of the fracturing system include: (1) evaluating the log-based diagenetic rock typing and flow index; (2) 1D mechanical earth model; (3) calculating the breakdown pressure envelope along the well trajectory of the landing part; (4) calculating the optimal perforation directions along the landing part; (5) select the first set of perforation locations based on the log-based diagenetic rock typing and flow index; (6) narrowing down the first set of perforation locations to a second set of perforation locations based on the breakdown pressure envelope; (7) determining a perforation strategy based on breakdown pressure envelope and wellhead pressure safety limit in the second set of perforation locations. The computational framework to calculate the breakdown pressure envelope and optimal perforation directions is applicable to arbitrary well trajectory. The fracturing system has been used to provide pre-fracturing suggestions for wells landed in deep and tight sandstone reservoirs, which is very efficient for identifying locations with good rock typing and relatively low breakdown pressure. Also, it can indicate whether oriented perforation should be used further for alleviating breakdown issue. By taking these efforts and procedures, the fracturing success rate for deep and tight sandstone gas reservoirs can be improved, which has been verified in practice. Example studies from the field will be provided to demonstrate the fracturing system's performance and applicability.

Coupling of nanostraws with diverse physicochemical perforation strategies for intracellular DNA delivery

Effective intracellular DNA transfection is imperative for cell-based therapy and gene therapy. Conventional gene transfection methods, including biochemical carriers, physical electroporation and microinjection, face challenges such as cell type dependency, low efficiency, safety concerns, and technical complexity. Nanoneedle arrays have emerged as a promising avenue for improving cellular nucleic acid delivery through direct penetration of the cell membrane, bypassing endocytosis and endosome escape processes. Nanostraws (NS), characterized by their hollow tubular structure, offer the advantage of flexible solution delivery compared to solid nanoneedles. However, NS struggle to stably self-penetrate the cell membrane, resulting in limited delivery efficiency. Coupling with extra physiochemical perforation strategies is a viable approach to improve their performance. This study systematically compared the efficiency of NS coupled with polyethylenimine (PEI) chemical modification, mechanical force, photothermal effect, and electric field on cell membrane perforation and DNA transfection. The results indicate that coupling NS with PEI modification, mechanical force, photothermal effects provide limited enhancement effects. In contrast, NS-electric field coupling significantly improves intracellular DNA transfection efficiency. This work demonstrates that NS serve as a versatile platform capable of integrating various physicochemical strategies, while electric field coupling stands out as a form worthy of primary consideration for efficient DNA transfection.

Mechanisms of Waterflood Inefficiency: Analysis of Geological, Petrophysical and Reservoir History, a Field Case Study of FWU (East Section)

The petroleum reservoir represents a complex heterogeneous system that requires thorough characterization prior to the implementation of any incremental recovery technique. One of the most commonly utilized and successful secondary recovery techniques is waterflooding. However, a lack of sufficient investigation into the inherent behavior and characteristics of the reservoir formation in situ can result in failure or suboptimal performance of waterflood operations. Therefore, a comprehensive understanding of the geological history, static and dynamic reservoir characteristics, and petrophysical data is essential for analyzing the mechanisms and causes of waterflood inefficiency and failure. In this study, waterflood inefficiency was observed in the Morrow B reservoir located in the Farnsworth Unit, situated in the northwestern shelf of the Anadarko Basin, Texas. To assess the potential mechanisms behind the inefficiency of waterflooding in the east half, geological, petrophysical, and reservoir engineering data, along with historical information, were integrated, reviewed, and analyzed. The integration and analysis of these datasets revealed that several factors contributed to the waterflood inefficiency. Firstly, the presence of abundant dispersed authigenic clays within the reservoir, worsened by low reservoir quality and high heterogeneity, led to unfavorable conditions for waterflood operations. The use of freshwater for flooding exacerbated the adverse effects of sensitive and migratory clays, further hampering the effectiveness of the waterflood. In addition to these factors, several reservoir engineering issues played a significant role in the inefficiency of waterflooding. These issues included inadequate perforation strategies due to the absence of detailed hydraulic flow units (HFUs) and rock typing, random placement of injectors, and uncontrolled injected fresh water. These external controlling parameters further contributed to the overall inefficiencies observed during waterflood operations in the east half of the reservoir. A detailed understanding of the mechanistic factors of inefficient waterflood operation will provide adequate insights into the development of the improved recovery technique for the field.

Bimetal Oxide Reduction-Induced Perforation Strategy for Preparing a Multi-Microchannel Graphene-Based Anode Material with Rapid Sodium-Ion Diffusion.

A sodium-ion battery, with a wide operating range, is much cheaper and safer than a lithium battery. Graphene is regarded as a promising carbon material in the preparation of anode materials. However, the large two-dimensional (2D) graphene sheets restrain the cross-plane diffusion of electrolyte ions, limiting the further improvement of rate performance. Herein, a nanohybrid of FeCo2Se4 and holey graphene (FeCo2Se4/HG) has been successfully prepared by the synchronism of pore creation and active material growth. Specifically, FeCo-oxide nanoparticles serve as the etching agents, generating in-plane nanoholes and subsequently converted into FeCo2Se4. The nanoholes provide a high density of cross-plane diffusion channels for sodium ions, serving as ionic diffusion shortcuts between different graphene layers to accelerate ion transport across the entire electrode. The unique architecture endows FeCo2Se4/HG with superior rate capability (411.2 mA h g-1 at 20 A g-1) and a specific capacity of 432.4 mA h g-1 at 2.0 A g-1 after 2000 cycles with a capacity retention rate of 92.4%. Therefore, pore engineering makes it possible for holey graphene-based electrodes to achieve outstanding rate performance and superb cycling durability.

Technology Focus: Hydraulic Fracturing Operations (June 2023)

With the global normalization of economies over the past 2 years after the pandemic, the demand for energy has only been increasing, and all forecasts show this demand will continue to grow. In light of the current geopolitical situation globally, balancing the energy trilemma (ensuring energy security, energy equity, and environmental sustainability) is a key global challenge. With the ever-increasing energy demand, oil and gas remains a major component within the energy mix to address this challenge and to aid in satisfying the growing demand. Hydraulic fracturing continues to be the main technology differentiator that enables enhancing recovery from both green- and brownfield reservoirs globally. During the past few years, the industry has made great strides in reducing carbon emissions through the deployment of new technologies in fracturing equipment manufacturing, including electric, hybrid, and turbine-driven fracturing equipment spreads. We have also seen the application of automation and emissions monitoring being widely adopted throughout the industry in an effort to lower the operational carbon footprint. Fracture monitoring to optimize fluid volumes and designs remains a critical area of development. Research is ongoing with the focus on combining different monitoring technologies including tracers, fiber optics, downhole cameras, and microseismic monitoring. There also have been innovations in using surface data to develop cost-effective solutions to monitor fracture-geometry propagation. Nanotracers and low-cost disposable fiber-optic cables have been areas that have seen increasing deployments within the monitoring realm. Cluster efficiency and stage spacing is being optimized in basins globally by studying perforation erosion, fracture propagation, and performance between various perforation strategies using different gun configurations in both single clusters and multiple clusters including extreme-limited-entry applications. We have seen improvements in the pressure ratings of dissolvable and flow-through plugs with the aim of aiding in improving turnaround efficiency in plug-and-perf wells. Multistage hardware has seen enhancements with new completion technologies such as cemented ball-drop multistage fracturing systems and multistage openhole systems with sand-screens that require minimum intervention being developed and deployed. Globally, we have observed increasing application of lessons learned to revamp older technologies and fracturing concepts such as the use of crosslinked gels, energized fluid systems, and tip screenout designs. In addition to conventional reservoirs, we also are seeing a growing application of stimulation and fracturing technologies being considered and deployed for geothermal applications. The recent technological developments and deployments cement the fact that hydraulic fracturing will remain an important pillar to solving the world’s energy requirements in the years to come. Recommended additional reading at OnePetro: www.onepetro.org. SPE 212342 Overflush and Fracturing: Playing Poker With Your Completion by Martin Rylance, THREE60 Energy SPE 212749 Natural-Gas-Powered Direct-Drive Turbine Hydraulic Fracturing Technology Delivers High-Power Density and Energy Transfer Efficiency for Environmental, Economic, and Operational Benefits by Guillermo Rodriguez, BJ Energy Solutions, et al. SPE 212322 Combined Video and Ultrasonic Measurements for Fracture Diagnostics—Greater Than the Sum of the Parts by Tobben Tymons, EV, et al. SPE 209159 Lessons Learned From the Large-Scale CO2 Stimulation of 11 Unconventional Wells in the Williston Basin: A Practical Review of Operations, Logistics, Production Uplift, and CO2 Storage by Lionel Ribeiro, Equinor, et al.

Unlocking the Full Potential of NMR Using Machine Learning: A Case Study of a Gas Field With an Oil Problem

This paper describes the application of machine-learning techniques for unlocking the full potential of nuclear magnetic resonance (NMR), using a case study from the Seven Heads gas field. This field has long been recognized but was not developed due to a variety of technical challenges, including the thin-bedded nature of the sediments and the presence of both mobile and immobile viscous residual oil. The oil is a highly viscous liquid which, if produced, could block production tubing due to the shallow depth of the reservoir and associated low pressures. To produce dry gas successfully, identification of both oil and gas zones was necessary to enable gas zones to be perforated and oil zones to be excluded. During the development drilling campaign, the reservoir was appraised using a formation evaluation program specifically designed to address the presence of oil within the thinly bedded reservoir. In conjunction with core data and high-resolution electric logs, NMR logs were used to identify and avoid perforating zones with higher oil saturations. Formation fluid types were derived from the NMR using a pattern recognition technique that analyzes the entire shape of the T1 and T2 distributions to derive the volumes of gas, oil, and water. This machine-learning technique was calibrated using Dean and Stark fluid analysis data and enabled the prediction of continuous water, gas, and oil saturation curves. The results were used to ensure that the perforation strategy avoided oil-bearing sands. This paper describes how the NMR, together with machine learning, has enabled a complex tight gas field to be developed.

Predicting fracture vertical growth containment using the width-induced net stress

The vertical growth of hydraulic fractures in layered formations is important from treatment-placement and well performance perspective. Most numerical fracture simulators generate fracture geometries by accounting for the in-situ stress and rock mechanical properties, along with key parameters related to fracturing fluids such as rheology and leakoff behavior, amongst various other critical parameters that can influence the outcome. Although the results from various simulators are generally reasonable, the fracture height estimates can vary significantly even for identical input data sets as shown in the literature. Because of the limitations of these simulators, some of the field observations, such as containment of fracture height growth across certain interfaces of contrasting material properties or weak interfacial bonding, are not replicated effectively, unless such an interface is pre-defined.In this study, the influence of fracture width on resultant stresses is incorporated in the calculation process while solving for vertical growth of hydraulic fractures. For this purpose, a modified equilibrium height growth model previously developed by the authors is used. The effects of viscous fluid movement in the fracture are also included in the calculation scheme.The outputs from the model were compared with the field-derived fracture heights that were inferred from micro seismic (MS) surveys conducted on various fracturing treatments that included both vertical and horizontal wells completed in layered formations. The analysis revealed a close agreement between the model-predicted and observed values of fracture height.While the authors acknowledge that predicting the containment of vertical growth of fracture across a plane is a challenging task given the complex nature of the problem, the paper discusses a method that offers a simpler approach to predicting the sites that may act as a constraint to the fracture growth during the stimulation treatments. This can aid in well-placement planning, perforation strategy, and hydraulic fracturing treatment design. The model can be readily deployed or incorporated in existing simulators.

Edge Water Breakthrough in each of the major zones within Mishrif reservoir in West Qurna phase 1

The Mishrif reservoir (Upper Cretaceous) considered the main discovered and developedreservoir at West Qurna I field in southern Iraq and has been on production intermittently since1999. Mishrif reservoir has been deviated into six main zones from youngest to oldest are mA,CRI, mB1, CRII, mB2 & mC.The West Qurna Phase I Field (WQI) has pressure depletion since production commenced in1999. More than 450 wells penetrated Mishrif Formation, to date, almost all of the productionhas been from the Mishrif formation (2180 to 2505 m true vertical depth, subsea) with minor oilproduction from the Lower Cretaceous Zubair formations. Geoscientist and reservoir engineersare looking for producing dry oil especially there are limited surface facilities at West Qurnaphase 1, for that purpose and as part of Reservoir Management, It was very important to monitorthe Formation & injection water movement across Mishrif reservoir with the time. Cased holelogs (Saturation logs & Production logs) and Open hole logs for new drill wells are beingintegrated to describe the water encroachment in Mishrif in order to Study behavior of aquifermovement and water injection, Validate the geologic reservoir model, assess the vertical andhorizontal water sweep & enhance perforation strategies.In West Qurna 1 (from 2010 to date) have been ran more than 500 PLTs (Production logs)and 300 PNLs (Saturation logs) and open hole logs for new drill wells, all these logs have beenanalysis and interpreted (using Geolog &Emeraude software) then were created different watermovement maps for each main productive zone mA, mB1 & mB2 in 2013, 2014 & 2016 (byPetrel).
 Different water encroachment behavior among the different zones due to heterogeneity inreservoir rock quality, Integrating production rate allocated by zone with water encroachmentmaps shows excellent relationship between production and flood front by zone, the maps showedthat quicker water movement in the Meshrif reservoir compared to the model, these maps areusing for perforation strategy, and the maps will be updated periodically every 12 months.

Design for Reliability: Experimental and Numerical Simulation of Cased and Perforated Completions with Standalone Screen

Summary The historical challenges and high failure rate of using standalone screen in cased and perforated wellbores pushed several operators to consider cased-hole gravel packing or frac packing as the preferred completion. Despite the reliability of these options, they are more expensive than a standalone screen completion. In this paper, we employ a combined physical laboratory testing and computational fluid dynamics (CFD) for laboratory scale and field scale to assess the potential use of the standalone screen in completing the cased and perforated wells. The aim is to design a fit-to-purpose sand control method in cased and perforated wells and provide guidelines in perforation strategy and investigate screen and perforation characteristics. More specifically, the simultaneous effect of screen and perforation parameters, near wellbore conditions on pressure distribution and pressure drop are investigated in detail. A common mistake in completion operation is to separately focus on the design of the screen based on the reservoir sand print and design of the perforation. If sand control is deemed to be required, the perforation strategy and design must go hand in hand with sand control design. Several experiments and simulation models were designed to better understand the effect of perforation density, the fill-up of the annular gap between the casing and screen, perforation collapse, and formation and perforation damage on pressure drop. The experiments consisted of a series of step-rate tests to investigate the role of fluid rate on pressure drop and sand production. There is a critical rate at which the sand filling up the annular gap will fluidize. Both test results and CFD simulation scenarios are comparatively capable to establish the relation between wellbore pressure drop and perforation parameters and determine the optimized design. The results of this study highlight the workflow to optimize the standalone screen design for the application in cased and perforated completions. The proper design of standalone screen and perforation parameters allows maintaining cost-effective well productivity. Results of this work could be used for choosing the proper sand control and perforation strategy.

Thermal Reductive Perforation of Graphene Cathode for High‐Performance Aluminum‐Ion Batteries

AbstractControlling the structure of graphene‐based materials with improved ion intercalation and diffusivity is crucial for their applications, such as in aluminum‐ion batteries (AIBs). Due to the large size of AlCl4− ions, graphene‐based cathodes have specific capacities of ≈60 to 148 mAh g−1, limiting the development of AIBs. A thermal reductive perforation (TRP) strategy is presented, which converts three‐layer graphene nanosheets to surface‐perforated graphene materials under mild temperature (400 °C). The thermal decomposition of block copolymers used in the TRP process generates active radicals to deplete oxygen and create graphene fragments. The resultant material has a three‐layer feature, in‐plane nanopores, >50% expanded interlayer spacing, and a low oxygen content comparable to graphene annealed at a high temperature of ≈3000 °C. When applied as an AIB cathode, it delivers a reversible capacity of 197 mAh g−1 at a current density of 2 A g−1 and reaches 92.5% of the theoretical capacity predicted by density‐functional theory simulations.

Implementation of Rock Typing on Waterflooding Process During Secondary Recovery in Oil Reservoirs: A Case Study, El Morgan Oil Field, Gulf of Suez, Egypt

Waterflooding is one of the most common secondary recovery methods in the oil and gas industry. Globally, this process sometimes suffers a technical failure and inefficiency. Therefore, a better understanding of geology, reservoir characteristics, rock typing and discrimination, hydraulic flow units, and production data is essential to analyze reasons and mechanisms of water injection failure in the injection wells. Water injection failure was reported in the Middle Miocene Hammam Faraun reservoir at El Morgan oil field in the Gulf of Suez, where two wells have been selected as injector’s wells. In the first well (A1), the efficiency of injection was not good, whereas in the other analog A2 well good efficiency was assigned. Therefore, it is required to assess the injection loss in the low efficiency well, where all aspects of the geological, reservoir and production data of the studied wells were integrated to get a complete vision for the reasons of injection failure. The available data include core analysis data (vertical and horizontal permeabilities, helium porosity, bulk density, and water and oil saturations), petrographical studies injection and reservoir water chemistry, reservoir geology, production, and injection history. The quality of the data was examined and a set of reliable X–Y plots between the available data were introduced and the reservoir quality in both wells was estimated using reservoir quality index, normalized porosity index, and flow zone indicator. Integration and processing of the core and reservoir engineering data indicate that heterogeneity of the studied sequence was the main reason for the waterflooding inefficiency at the El Morgan A1 well. The best reservoir quality was assigned to the topmost part of the reservoir, which caused disturbance of the flow regime of reservoir fluids. Therefore, it is clearly indicated that rock typing and inadequate injection perforation strategy that has not been aligned with accurate hydraulic flow units are the key control parameters in the waterflooding efficiency.

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.

Petrophysical evaluation of clastic Upper Safa Member using well logging and core data in the Obaiyed field in the Western Desert of Egypt

Upper Safa Member is part of Jurassic Khatatba Formation; it consists of low net gross ratio sand streaks. The core and well logging data were used to perform a comprehensive reservoir evaluation. The Schlumberger application “Techlog” was used to perform the required evaluation analysis. Four oriented wells were selected for this study. The volume of shale “Vsh” using gamma-ray (GR) was used to evaluate the lithology and to discriminate sand “reservoir” from shale “non-reservoir”. A porosity model using the density log was constructed and used as an input to calculate Archie’s water saturation “Sw”. Porosity- Permeability (Poro-Perm) Transform was used to evaluate the reservoir permeability. The net reservoir and net pay thicknesses were seen attractive in three out of four wells. The reservoir quality parameters “Porosity and Permeability” were different from well to well. The hydrocarbon saturation “Sh” was high in the three wells. The hydrocarbon intervals depths were highlighted and considered in the perforation strategy.

Analytical orientation criteria for drilling and completion-induced fracture initiation considering fluid infiltration from the wellbore

Analytically-developed criteria are presented for the orientation of fracture initiation in porous-permeable rocks considering fluid infiltration from non-perforated and perforated wellbores. For non-perforated wellbores, this is a fully-exact analytical solution representing the initiation of drilling-induced tensile fractures (DITFs). For perforated wells, a set of analytical approximations are derived for fracture initiation representing completion-induced hydraulic fractures (CIHFs). DITF orientation is used to constrain the in-situ stress tensor, especially in the case of transverse DITFs, which are rarer than longitudinal DITFs. Results indicate that transverse CIHF initiation only occurs over a wellbore pressure-at-breakdown window, while longitudinal CIHF initiation occurs at comparatively higher wellbore pressures. Transverse CIHF initiation however, occurs more frequently than transverse DITFs, because the presence of perforations aids transverse fracture initiation. Low Biot's poroelastic coefficient and high Poisson's ratio values also aid transverse fracture initiation. The region of the in-situ stress states where transverse initiation is promoted can be shown in dimensionless plots. Case studies are run on seven prolific shale plays (Barnett, Bakken, Fayetteville, Haynesville, Niobrara, Marcellus, and Vaca Muerta) using breakdown pressures from the literature. Transverse CIHF initiation is found to be a highly likely outcome, as opposed to results from past studies that neglected pore pressure effects. Based on the findings of this study, recommendations are made to practitioners to enhance their chances on achieving transverse CIHF initiation in the field. These involve slow injection rates, oriented perforation strategy and strong bonding between the casing, cement and the surrounding rock to prevent fracturing fluid leakages.

Non-uniform injector/producer well pattern designs induced by morphology and anisotropy of flow units

Well patterns are designed to comply with specific demands of engineering and usually applied in multilateral layouts for steam-/water-/fire-flooding or other operations in oilfields. Up to now, there is no much information about the linkage between anisotropy effects and preferential flow direction as a driving factor for enhanced well pattern designs, especially in heterogeneous reservoirs. This paper introduces a methodology to design non-uniform areal well patterns typified as 5-spot injector/producer arrangements of vertical wells. In particular, its original feature relies on well patterns derived in relation to flow units. Once these volumetric bodiesare detected, the well placement is formed in coherence with their morphology to pursue the predominant flow direction implicitly. We apply an ellipsoid-fitting technique that provides “boundary-fitted” locations for the injector wells that coincide with anchor points on the volume of interest's convex hull. Anchor points are those determined from minimum distances of other points that lie on the principal axes of the best-fit ellipsoid to the flow unit. A class of well patterns derived through rotations by common angles (π/6, π/4 and π/3) and aligned to match the volume's anisotropy is obtained by combining injection points and production spots found from the maximum closeness centrality of the graph associated to the shape. Flow simulations with water-flooding performed in two reservoir models with heterogeneous features show that the hydrocarbon recovery is higher or lower depending on the positions of the injection spots. Single and multiple perforation strategies are examined over flow units with distinct shapes and characteristics to broaden the spectrum of testing conditions. When compared with the traditional water-flooding 5-spot configuration, many cases achieve similar ultimate productions that are influenced to an extent by morphological aspects. The main advantage of the method is to deliver a pragmatic workflow to design directional well patterns which dismisses the solution of more complicated differential models to determine the patterns.

Optimization of Plug-and-Perforate Completions for Balanced Treatment Distribution and Improved Reservoir Contact

Summary Heel-dominated treatment distribution among multiple perforation clusters is frequently observed in plug-and-perforate (plug-and-perf) stages, causing small propped surface areas, suboptimal production, and unexpected fracture hits. A multifracture simulator with a novel wellbore-fluid and proppant-transport model is applied to quantify treatment distribution among multiple perforation clusters in a plug-and-perf operation. A simulation base case is set up on the basis of a field treatment design with four clusters. Simulation results show that the two toe-side clusters screened out early in the treatment and the two heel-side clusters were dominant. The simulated proppant placement is consistent with distributed-acoustic-sensing observations. The impact of different perforating strategies and pumping schedules on final treatment distribution is investigated. Two criteria are defined that quantify the proppant distribution and fracture area: the weighted average (WA) and standard deviation (SD) of the final fluid and proppant distribution, as well as the hydraulic surface area (HSA) and propped surface area (PSA) of the created fractures. An optimal plug-and-perf design is defined as one that minimizes the SD of the treatment distribution among perforation clusters, and maximizes the PSA. Both perforating strategy and pumping schedule are found to affect the final treatment distribution significantly, and uniform treatment distribution is shown to create more PSA. Having fewer perforations per cluster was found to promote uniform fluid and proppant placement. Other helpful strategies include reducing the number of perforations near the heel and using small, lightweight proppant. The stress shadow effect is accounted for using the displacement discontinuity method (DDM) and was found to play a smaller role than perforation friction and proppant inertia in most cases. An automated process is developed to optimize plug-and-perf completion design with multiple decision variables using a genetic algorithm (GA). Thirteen parameters are optimized simultaneously. The optimal design solution creates an almost even treatment distribution and more than doubles the PSA compared with the base case. The multifracture model presented in this paper provides a way to quantify fluid and proppant distribution for any perforating strategy and pumping schedule, and provides more insight into the physics relevant to plug-and-perf treatment distribution. The perforation and pumping schedule recommendations presented in this paper provide directional guidance for the design of fracturing jobs with balanced treatment distribution and large PSA.

Development of a Numerical Model for Single- and Two-Phase Flow Simulation in Perforated Porous Media

Abstract In this paper, we present a computational fluid dynamics (CFD) model to perform single- and two-phase fluid flow simulation on two- and three-dimensional perforated porous media with different perforation geometries. The finite volume method (FVM) has been employed to solve the equations governing the fluid flow through the porous media and obtain the pressure and velocity profiles. The volume of fluid (VOF) method has also been utilized for accurate determination of the volume occupied by each phase. The validity of the model has been achieved via comparing the simulation results with the available experimental data in the literature. The model was used to analyze the effect of perforation geometrical parameters (length and diameter), degree of heterogeneity, and also crushed zone properties (permeability and thickness) on the pressure and velocity profiles. The two-phase fluid flow around the perforation tunnel under the transient flow regime was also investigated by considering a constant mass flow boundary condition at the inlet. The developed model successfully predicted the pressure drop and resultant temperature changes for the system of air–water along clean and gravel-filled perforations under the steady-state conditions. The presented model in this study can be used as an efficient tool to design the most appropriate perforation strategy with respect to the well characteristics and reservoir properties.

A new mathematical model for horizontal wells with variable density perforation completion in bottom water reservoirs

Horizontal wells are commonly used in bottom water reservoirs, which can increase contact area between wellbores and reservoirs. There are many completion methods used to control cresting, among which variable density perforation is an effective one. It is difficult to evaluate well productivity and to analyze inflow profiles of horizontal wells with quantities of unevenly distributed perforations, which are characterized by different parameters. In this paper, fluid flow in each wellbore perforation, as well as the reservoir, was analyzed. A comprehensive model, coupling the fluid flow in the reservoir and the wellbore pressure drawdown, was developed based on potential functions and solved using the numerical discrete method. Then, a bottom water cresting model was established on the basis of the piston-like displacement principle. Finally, bottom water cresting parameters and factors influencing inflow profile were analyzed. A more systematic optimization method was proposed by introducing the concept of cumulative free-water production, which could maintain a balance (or then a balance is achieved) between stabilizing oil production and controlling bottom water cresting. Results show that the inflow profile is affected by the perforation distribution. Wells with denser perforation density at the toe end and thinner density at the heel end may obtain low production, but the water breakthrough time is delayed. Taking cumulative free-water production as a parameter to evaluate perforation strategies is advisable in bottom water reservoirs.

Competitive placement of oil perforation zones in hydraulic flow units from centrality measures

This paper applies graph centrality measures to suggest a competitive placement of perforation zones in oil reservoirs. Datasets available in an online repository are used to build a synthetic field model in which porosity and permeability are known everywhere. From this field, a reservoir associated to a central oil well chosen randomly is extracted so as to form a volume containing distinct groups of petrophysical regions. Combined with the well-known FZI/DRT (flow zone indicator/discrete rock type) techniques, which identifies hydraulic flow units by means of linear regression best-fit lines and conversion formulae, high-performance clusters, as well as their respective target zones, are identified in the reservoir. Each cluster is modelled as an irregular set of face-connected cells and additionally mapped onto undirected graphs. Individual numerical simulations of production wellbores placed at testing and target zones are performed for several clusters. We find that when the wellbores are placed exactly at those vertices whose closeness centrality measure is maximum, considerable oil recovery factors are achieved, thereby suggesting highly competitive perforation zones. We conjecture that the current approach may be used as a decision-making tool to allocate production zones and choose economically viable perforation strategies for implementation during the stages of drilling and production.

Simulation on Heavy Oil Production from Steam-Flooding

Heavy-oil is one of the main energy sources in the future. However, with the high viscosity of heavy oil, steam-flooding (SF) is one of the major techniques to produce this oil. To determine a favorable operating condition, many recent studies have evaluated the different methods like varying the well spacing and steam injection rates. However, there is no single optimum value for all reservoirs or all modes of operation. In this study, it’s aimed to investigate the effects of well spacing, injection rate, and perforation on heavy oil production with low permeability in multi-layered heterogeneous reservoir. The practical field data was applied to simulate the SF process by using STARS, a CMG program. Production parameters such as injector – producer (inj. – prod.) distance from 141 m to 282 m and steam injection rates from 30 m3/d to 180 m3/d were evaluated to obtain the optimum conditions with 80 % steam quality. The entire project was considered for 20 years of production. From the results, it showed that the higher oil recovery can be achieved by increasing injection rate and/or shorten well spacing. In order to lower the steam consumption, the selective perforation in bottom layers was compared with full perforation strategy. With the balance between oil production and steam injection, about 60 % of steam can be saved in terms of water barrels (bbls). Meanwhile, it’s possible to achieve a longer project life due to the slow depletion rate.