Application of Interventionless Single Point Entry Technology to Improve Proppant Placement Control and Well Production

2021 ◽  
Author(s):  
J. Griffin ◽  
D. J. Rojas ◽  
A. Al Shmakhy ◽  
P. Scranton
Keyword(s):  
Single Point ◽  
Production Performance ◽  
Carbon Intensity ◽  
Well Performance ◽  
Well Production ◽  
Coiled Tubing ◽  
Multi Stage ◽  
Entry Points ◽  
Asset Development ◽  
Cluster Efficiency

Abstract The hydraulic fracture treatment (HFT) and its effectiveness to enhance wellbore drainage directly correlate with each well’s overall production performance and underlining economics. This paper will discuss the potential of ultra high stage count Single Point Entry (SPE) sleeves and their ability to increase control over proppant placement and isolation during the HFT as a method for optimizing well performance, economics, and reduce non-uniformity between treatments and wells. To address the limitations of current completion methods, full ID single point entry systems have been developed for open hole and cemented applications. These systems provide unlimited frac stage count with lower frac tortuosity, provide increased control over proppant placement and well production, reduce or eliminate over- flush and formation damage, and achieve higher efficiency during and after frac stimulation than previous conventional plug-and-perf (PnP) and sleeve systems, thereby reducing costs. While the ball-and-seat completion technique revolutionized the efficiency of multi-stage single point entry fracturing, its vast array of limitations (primarily ID restrictions), limited stage count, and compatibility with cemented liners quickly sidelined it in place of PnP. PnP offers increased surface area contact through additional entry points compared to sleeve systems of the past and remains the accepted method for achieving zonal isolation and initiation during stimulation. However, the time intensive operations of PnP present challenges in maintaining efficiencies due to variability in wireline during deployment and coiled tubing during millouts. The increase in number of clusters per stage and number of stages per well achieved with PnP often results in higher stimulated rock volumes (SRV) however, due to the number of multiple clusters open simultaneously, this method gained a "pump-n-pray" reputation due to the uncertainty of cluster efficiency and its unpredictability. The lack of cluster control over the years has created a series of challenges in terms of parent-child well relationships and spacing, economical asset development, and loss of potential production. With over 4,000 stages fracture stimulated across US, Canada, and Asia, some wells containing 220 individual stages, this paper will address the differences in production in terms of bbl of oil equivalent (BOE) for direct and indirect offsets in trials, compare capital efficiency with spud to put on production (POP) timelines, demonstrate economical completion optimization for lower commodity pricing of oil, and carbon intensity reduction measures to lower greenhouse gas emissions.

Key Factors in Shale Gas Modeling and Simulation

2014 ◽  
Vol 59 (4) ◽  
pp. 987-1004 ◽  
Author(s):  
Łukasz Klimkowski ◽  
Stanisław Nagy
Keyword(s):  
Shale Gas ◽  
Gas Production ◽  
Production Performance ◽  
Hydraulic Fractures ◽  
Well Performance ◽  
Key Factors ◽  
Gas Well ◽  
Well Production ◽  
Multi Stage ◽  
The Impact

Abstract Multi-stage hydraulic fracturing is the method for unlocking shale gas resources and maximizing horizontal well performance. Modeling the effects of stimulation and fluid flow in a medium with extremely low permeability is significantly different from modeling conventional deposits. Due to the complexity of the subject, a significant number of parameters can affect the production performance. For a better understanding of the specifics of unconventional resources it is necessary to determine the effect of various parameters on the gas production process and identification of parameters of major importance. As a result, it may help in designing more effective way to provide gas resources from shale rocks. Within the framework of this study a sensitivity analysis of the numerical model of shale gas reservoir, built based on the latest solutions used in industrial reservoir simulators, was performed. The impact of different reservoir and hydraulic fractures parameters on a horizontal shale gas well production performance was assessed and key factors were determined.

Novel Near-Wellbore Fracture Diagnosis for Unconventional Wells Using High-Resolution Distributed Strain Sensing during Production

SPE Journal ◽  
2021 ◽  
pp. 1-10
Author(s):  
Ge Jin ◽  
Gustavo Ugueto ◽  
Magdalena Wojtaszek ◽  
Artur Guzik ◽  
Dana Jurick ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Fiber Optic ◽  
Fracture Network ◽  
Production Performance ◽  
Hydraulic Fractures ◽  
Fracture Aperture ◽  
Strain Sensing ◽  
Extensional Strain ◽  
Cluster Efficiency ◽  
Distributed Strain

Summary The characteristics of hydraulic fractures in the near-wellbore region contain critical information related to the production performance of unconventional wells. We demonstrate a novel application of a fiber-optic-based distributed strain sensing (DSS) technology to measure and characterize near-wellbore fractures and perforation cluster efficiency during production. Distributed fiber-optic-based strain measurements are made based on the frequency shift of the Rayleigh scatter spectrum, which is linearly dependent on strain and temperature changes of the sensing fiber. Strain changes along the wellbore are continuously measured during the shut-in and reopening operations of a well. After removing temperature effects, extensional strain changes can be observed at locations around the perforation cluster during a shut-in period. We interpret that the observed strain changes are caused by near-wellbore fracture aperture changes caused by pressure increases within the near-wellbore fracture network. The depth locations of the measured strain changes correlate well with distributed acoustic sensing (DAS) acoustic intensity measurements that were measured during the stimulation of the well. The shape and magnitude of the strain changes differ significantly between two completion designs in the same well. Different dependencies between strain and borehole pressure can be observed at most of the perforation clusters between the shut-in and reopening periods. We assess that this new type of distributed fiber-optic measurement method can significantly improve understanding of near-wellbore hydraulic fracture characteristics and the relationships between stimulation and production from unconventional oil and gas wells.

Application Investigation of Light Proppant in Hydraulic Fracturing of Marcellus Shale

2021 ◽  
Author(s):  
Aymen Alhemdi ◽  
Ming Gu
Keyword(s):  
History Matching ◽  
Marcellus Shale ◽  
In Situ Stress ◽  
Production Performance ◽  
Well Performance ◽  
Fracture Permeability ◽  
Fracture Conductivity ◽  
Stimulated Reservoir Volume ◽  
Conductivity Distribution ◽  
Cumulative Production

Abstract Slickwater-sand fracturing design is widely employed in Marcellus shale. The slickwater- sand creates long skinny fractures and maximizes the stimulated reservoir volume (SRV). However, due to the fast settling of sand in the water, lots of upper and deeper areas are not sufficiently propped. Reducing sand size can lead to insufficient fracture conductivity. This study proposes to use three candidate ultra-lightweight proppants ULWPs to enhance the fractured well performance in unconventional reservoirs. In step 1, the current sand pumping design is input into an in-house P3D fracture propagation simulator to estimate the fracture geometry and proppant concentrations. Next, the distribution of proppant concentration converts to conductivity and then to fracture permeability. In the third step, the fracture permeability from the second step is input into a reservoir simulator to predict the cumulative production for history matching and calibration. In step 4, the three ULWPs are used to replace the sand in the frac simulator to get new frac geometry and conductivity distribution and then import them in reservoir model for production evaluation. Before this study, the three ULWPs have already been tested in the lab to obtain their long-term conductivities under in-situ stress conditions. The conductivity distribution and production performance are analyzed and investigated. The induced fracture size and location of the produced layer for the current target well play a fundamental effect on ultra-light proppant productivity. The average conductivity of ULWPs with mesh 40/70 is larger and symmetric along the fracture except for a few places. However, ULWPs with mesh 100 generates low average conductivity and create a peak conductivity in limited areas. The ULW-3 tends to have less cumulative production compared with the other ULWPs. For this Marcellus Shale study, the advantages of ultra-lightweight proppant are restricted and reduced because the upward fracture height growth is enormous. And with the presence of the hydrocarbon layer is at the bottom of the fracture, making a large proportion of ULWPs occupies areas that are not productive places. The current study provides a guidance for operators in Marcellus Shale to determine (1) If the ULWP can benefit the current shale well treated by sand, (2) what type of ULWP should be used, and (3) given a certain type of ULWP, what is the optimum pumping schedule and staging/perforating design to maximize the well productivity. The similar workflow can be expanded to evaluate the economic potential of different ULWPs in any other unconventional field.

Worlds First Offshore Horizontal Well Using Jointed Pipe Cemented Frac Sleeve Technology

2022 ◽  
Author(s):  
Shaun Thomson ◽  
Baglan Kiyabayev ◽  
Barry Ritchie ◽  
Jakob Monberg ◽  
Maurits De Heer ◽  
...  
Keyword(s):  
North Sea ◽  
New Technology ◽  
Production Performance ◽  
New Developments ◽  
Coiled Tubing ◽  
The North ◽  
New Novel ◽  
The North Sea ◽  
Reservoir Connectivity ◽  
First Job

Abstract The Valdemar field, located in the Danish sector of the North Sea, targets a Lower Cretaceous, "dirty chalk" reservoir characterized by low permeabilities of <0.5mD, high porosities of >20% and contains up to 25% insoluble fines. To produce economically the reservoir must be stimulated. Typically, this is by means of hydraulic fracturing. A traditional propped fracture consists of 500,000 to 1,000,000 lbs of 20/40 sand, placed using a crosslinked seawater-based borate fluid. The existing wells in the field are completed using the PSI (perforate, isolate, stimulate)1 system. This system was developed in the late 1980s as a way of improving completion times allowing each interval to be perforated, stimulated and isolated in a single trip and has been used extensively in the Danish North Sea in a variety of fields. The system consists of multiset packers with sliding sleeves and typically takes 2-3 days between the start of one fracture to the next. Future developments in this area now require a new, novel and more efficient approach owing to new target reservoir being of a thinner and poorer quality. In order for these new developments to be economical an approach was required to allow for longer wells to be drilled and completed allowing better reservoir connectivity whilst at the same time reducing the completion time, and therefore rig time and overall cost. A project team was put together to develop a system that could be used in an offshore environment that would satisfy the above criteria, allowing wells to be drilled out to 21,000ft and beyond in excess of coiled tubing reach. The technology developed consists of cemented frac sleeves, operated with jointed pipe, allowing multiple zones to be stimulated in one trip, as well as utilizing a modified BHA that allows for the treatments to take place through the tubing, bringing numerous benefits. The following paper details the reasons for developing the new technology, the development process itself, the challenges that had to be overcome and a case history on the execution of the first job of its kind in the North Sea, in which over 7MM lbs of sand was pumped successfully, as well as the post treatment operations which included a proof of concept in utilizing a tractor to manipulate the sleeves. Finally, the production performance will be discussed supported by the use of tracer subs at each of the zones.

Improving Well Production Performance By Using Realtime Wash Desalting Planning Tool WDPT in the North Sea

2020 ◽  
Author(s):  
Ryvo Octaviano ◽  
Erik Hornstra ◽  
Jonah Poort ◽  
Pejman Shoeibi Omrani ◽  
Ruud van der Linden ◽  
...  
Keyword(s):  
North Sea ◽  
Production Performance ◽  
Planning Tool ◽  
Well Production ◽  
The North ◽  
The North Sea

scholarly journals A Review on “Management by Exception” Surveillance for Well Management: To maximize Oil Production

2018 ◽  
Vol 7 (3.25) ◽  
pp. 90
Author(s):  
Azlinda Abdul Malik ◽  
Mohd Hilmi Hasan ◽  
Mazuin Jasamai
Keyword(s):  
Literature Review ◽  
Business Processes ◽  
Oil And Gas ◽  
Production Performance ◽  
Data Driven ◽  
Well Production ◽  
Monitoring Well ◽  
Oil And Gas Operations ◽  
Manual Interaction ◽  
Structured Literature Review

The business processes and decisions of oil and gas operations generate large amounts of data, which causes surveillance engineers to spend more time gathering, and analyzing them. To do this manually is inefficient. Hence, this study is proposed to leverage on data driven surveillance by adopting the principle of management by exception (MBE). The study aims to minimize the manual interaction between data and engineers; hence will focus on monitoring well production performance through pre-determined parameters with set of rules. The outcome of this study is a model that can identify any deviations from the pre-set rules and the model will alert user for deviations that occur. The model will also be able to predict on when the well be offline if the problem keeps on persisting without immediate action from user. The objective of this paper is to present a literature review on the prediction and management by exception for the above mentioned well management. The results presented in this paper will help in the development of the proposed prediction and management model. The literature review was conducted based on structured literature review methodology, and a comparative study among the collected works is analyzed and presented in this paper.  

scholarly journals Optimizing Production Schedule of Coalbed Methane Wells Using a Stochastic Evolution Algorithm

2020 ◽  
Vol 2020 ◽  
pp. 1-19
Author(s):  
Qiujia Hu ◽  
Xianmin Zhang ◽  
Xiang Wang ◽  
Bin Fan ◽  
Huimin Jia
Keyword(s):  
Production Rate ◽  
Coalbed Methane ◽  
Optimization Problem ◽  
Production Optimization ◽  
Production Performance ◽  
Production Schedule ◽  
Schedule Optimization ◽  
Well Production ◽  
Control Frequency ◽  
Optimized Schedule

Production optimization of coalbed methane (CBM) is a complex constrained nonlinear programming problem. Finding an optimal decision is challenging since the coal seams are generally heterogeneous with widespread cleats, fractures, and matrix pores, and the stress sensitivities are extremely strong; the production of CBM wells needs to be adjusted dynamically within a reasonable range to fit the complex physical dynamics of CBM reservoirs to maximize profits on a long-term horizon. To address these challenges, this paper focuses on the step-down production strategy, which reduces the bottom hole pressure (BHP) step by step to expand the pressure drop radius, mitigate the formation damage, and improve CBM recovery. The mathematical model of CBM well production schedule optimization problem is formulated. The objective of the optimization model is to maximize the cumulative gas production and the variables are chosen as BHP declines of every step. BHP and its decline rate constraints are also considered in the model. Since the optimization problem is high dimensional, nonlinear with many local minima and maxima, covariance matrix adaptation evolution strategy (CMA-ES), a stochastic, derivative-free intelligent algorithm, is selected. By integrating a reservoir simulator with CMA-ES, the optimization problem can be solved successfully. Experiments including both normal wells and real featured wells are studied. Results show that CMA-ES can converge to the optimal solution efficiently. With the increase of the number of variables, the converge rate decreases rapidly. CMA-ES needs 3 or even more times number of function evaluations to converge to 100% of the optimum value comparing to 99%. The optimized schedule can better fit the heterogeneity and complex dynamic changes of CBM reservoir, resulting a higher production rate peak and a higher stable period production rate. The cumulative production under the optimized schedule can increase by 20% or even more. Moreover, the effect of the control frequency on the production schedule optimization problem is investigated. With the increases of control frequency, the converge rate decreases rapidly and the production performance increases slightly, and the optimization algorithm has a higher risk of falling into local optima. The findings of this study can help to better understanding the relationship between control strategy and CBM well production performance and provide an effective tool to determine the optimal production schedule for CBM wells.

scholarly journals Production Rate Analysis of Fractured Horizontal Well considering Multitransport Mechanisms in Shale Gas Reservoir

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-17 ◽  
Author(s):  
Qi-guo Liu ◽  
Wei-hong Wang ◽  
Hua Liu ◽  
Guangdong Zhang ◽  
Long-xin Li ◽  
...  
Keyword(s):  
Production Rate ◽  
Shale Gas ◽  
Horizontal Well ◽  
Production Performance ◽  
Natural Fractures ◽  
Gas Reservoir ◽  
Isothermal Adsorption ◽  
Well Production ◽  
Shale Gas Reservoir ◽  
Fractured Horizontal Well

Shale gas reservoir has been aggressively exploited around the world, which has complex pore structure with multiple transport mechanisms according to the reservoir characteristics. In this paper, a new comprehensive mathematical model is established to analyze the production performance of multiple fractured horizontal well (MFHW) in box-shaped shale gas reservoir considering multiscaled flow mechanisms (ad/desorption and Fick diffusion). In the model, the adsorbed gas is assumed not directly diffused into the natural macrofractures but into the macropores of matrix first and then flows into the natural fractures. The ad/desorption phenomenon of shale gas on the matrix particles is described by a combination of the Langmuir’s isothermal adsorption equation, continuity equation, gas state equation, and the motion equation in matrix system. On the basis of the Green’s function theory, the point source solution is derived under the assumption that gas flow from macropores into natural fractures follows transient interporosity and absorbed gas diffused into macropores from nanopores follows unsteady-state diffusion. The production rate expression of a MFHW producing at constant bottomhole pressure is obtained by using Duhamel’s principle. Moreover, the curves of well production rate and cumulative production vs. time are plotted by Stehfest numerical inversion algorithm and also the effects of influential factors on well production performance are analyzed. The results derived in this paper have significance to the guidance of shale gas reservoir development.

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