Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
flow regime
Abstract Most of interpretation and analysis procedures developed for pressure transients acquired by multi-probe and packer-probe wireline formation testers (WFTs) are used to conduct are based on the slightly compressible fluid of constant viscosity and compressibility. Hence, these interpretation and analysis procedures apply for oil and water bearing formations. There is a concern that the interpretation/analysis methods based on the assumption of slightly compressible fluid may not be applicable in the case of testing a single-layer or a multi-layer gas zone(s) with the effects of nonlinear gas properties including non-Darcy flow for multi-probe or packer-probe wireline formation testers. In the literature, to the best of our knowledge, there is no a comprehensive study investigating the validity of the above stated assumption for the interpretation of WFT pressure transient data in gas zones. In this work, variety of cases considered for investigating the effect (or sensitivity) of non-linear gas flow on the pressure transients from multi-probe and packer-probe wireline formation testers (WFTs). These effects include gas gravity, variation of gas viscosity and compressibility with pressure, non-Darcy flow, position of active (flowing) and observation probes, mechanical skin and radius of skin (or invaded) zone, and reservoir heterogeneity in the vertical direction. A three-dimensional r-ฮธ-z single-phase-gas fully-implicit finite-difference model for a limited-entry vertical well has been developed for the purpose of this investigation. The results show that for multi-probe wireline testers, the sink (or the flowing) and horizontal probe pressure responses are highly affected by the effects of the non-Darcy flow and invaded zone, while the vertical probe pressures are mainly influenced by the properties of the uninvaded zones with non significant non-Darcy flow effect. For packer-probe testers, similar results are obtained. Both synthetic cases are presented to confirm the theory and procedures developed in this work.
- Europe (0.68)
- North America > United States > Texas (0.46)
- Asia > Middle East > Turkey (0.29)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract A dual purpose design is presented in this paper to face high gas presence and sand production conditions in petroleum wells with an Electric Submersible Pump (ESP) system installed. The results of this design's application in severely problematic wells, due to high gas and sand production, will confirm the importance of conditioning the fluid before it gets to the pump intake. This engineered design consists of different stages from the isolation of the pump intake until the tubing bodies in charge of gas and sand handling. Engineering concepts were applied in the construction of this solution such as gas re-solubilization, changes of pressure and velocity, agitation, and vortex effect to finally present a design that is capable of breaking gas slugs into smaller gas bubbles that can be produced by the ESP system without impacting its performance, and at the same time separating fine solid particles (<250 microns) using centrifugal forces. Case studies from wells located in the Permian basin will better explain the positive impact of selecting a proper downhole conditioning system to improve the ESP systems efficiency. A drastic improvement on the sensor parameters will also illustrate the effect of handling the gas and sand before the pump intake, which also leads to one of the most important consequences: A decrease in the number of shutdowns, which in turn decreases non-productive time, resulting in positive impact of fluid production. Additionally, the flexibility of this design is significant, since it allows it to be installed in a wide range of fluid production, gas-liquid ratio, tubing and casing sizes. The novelty of this new design is the addition of the surge valve below the packer, which accomplishes multiple purposes: to avoid surging in the well, to allow testing the packer to assure it is properly set, and finally, allow chemical injection below the packer.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.90)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206108, โDiagnostic Plots of Pressure-Transient, Rate-Transient, and Diagnostic Fracture Injection/Falloff Tests,โ by David Craig, SPE, Occidental, and Thomas Blasingame, SPE, Texas A&M University. The paper has not been peer reviewed. _ All transient-test interpretation methods use diagnostic plots for the identification of wellbore or fracture storage distortion, flow regimes, and other parameters. The associated diagnostic plots are not interchangeable between such tests. The objective of this work is to clearly define the appropriate diagnostic plots for each type of transient test. Introduction In the complete paper, the authors review constant-rate drawdown solutions for a few specific cases of interest and the plotting function used to match buildup data to the drawdown solutions. They extend their review to the cases of buildup or falloff analysis following short flow periods and illustrate the differences between analysis of buildup or falloffs following short and long flow periods. After covering pressure-transient testing, they discuss rate-transient diagnostic plots and the ambiguity observed during analysis of multifractured horizontal well diagnostic plots and the uncertainty of analyst straight lines. Finally, they discuss and demonstrate the correct plotting functions and flow-regime interpretation for diagnostic fracture injection and falloff tests. Multiple examples from the literature are included as part of the discussion. Pressure-Transient Diagnostic Plots Pressure-transient-testing diagnostic plots evolved from the solutions to constant-rate drawdown problems. The authorsโ intent is to review infinite-acting solutions for radial flow with wellbore storage and skin and flow through an infinite-conductivity fracture. On a log-log plot, the characteristic slopes, detailed in the complete paper, are unit slope, ยฝ slope, and zero slope. Many authors have proposed plotting functions for overlaying the observed pressure response from transient tests other than a constant-rate drawdown on the drawdown solutions. In many cases, the slopes identifying storage distortion and flow regimes from drawdown solutions will match and can be used to identify storage and flow regimes from pressure-buildup tests. A situation in which pressure-buildup or falloff test plotting functions fail to match the drawdown solution is when the flow period before shut-in is short. Short-flow transient tests have been reviewed by multiple authors. In lower-permeability reservoirs, pressure-transient tests with short flow periods are very common, and, in unconventional reservoirs, short-flow transient tests are the most-common transient test. Diagnostic plots constructed based on the characteristic shapes of the dimensionless pressure and the dimensionless pressure derivative with respect to the natural logarithm of dimensionless time for constant-rate drawdown solutions cannot be applied in the same manner for short-flow transient tests. With short-flow transient tests, the observed derivative of pressure difference with respect to the natural logarithm of time matches the negative product of dimensionless time and the second derivative of dimensionless pressure with respect to dimensionless time. Additionally, the commonly known impulse derivative, which is defined as the product of time and the derivative of pressure difference with respect to the natural logarithm of time, will match the negative product of dimensionless time squared and the second derivative of dimensionless pressure with respect to dimensionless time.
More than three dozen oil and gas producers are working together to solve one of the grand challenges faced by all in the increasingly global unconventional sector. That is the ability to better predict tight-oil and -gas production using rate transient analysis (RTA). Considered an โunconventional diagnosticโ when first introduced in the 1970s, RTA relies on fluid rates and flowing pressures to inform engineers on what their reservoirs will ultimately yield. Unfortunately, the low permeability of tight rocks and a myriad of dynamics stemming from hydraulic fracturing have undercut the simplicity of the tool. This has given rise to arguments that RTA is not a fit for unconventional reservoirs. But a joint industry project with 37 operators from around the world is betting against that notion. Those taking part represent the biggest and most active shale plays in the USโa list that includes Apache Corp., BPโs shale unit BPx. Devon Energy, EQT, Hess Corp., and Ovintiv. Others hold assets in Canadaโs Montney and Duvernay formations, Argentinaโs Vaca Muerta Shale, and the emerging Jafurah tight-gas basin that Saudi Aramco is in the early stages of developing. The organizer behind the joint project is petroleum engineering software and consultancy Whitson. The Trondheim-based firm said the client consortium is likely the largest of its kind to focus squarely on improving RTA for tight reservoirs. In October, the multinational group wrapped up its first phase of study with a set of best practices and the release of new add-ons for Whitsonโs software service. Why this might evolve into a notable development is because the deliverables are all designed to help standardize a recently debuted alternative called the numerically enhanced RTA workflow. Introduced by reservoir experts at Houston-based Apache and IHS Markit, this โenhancedโ version of numerical RTA has caught the industryโs attention for its ability to account for the effects of multiphase flow in tight wells. The first details about the approach were shared with the industry in 2020 in URTeC 2967. Whitson reports that a newly established workflow for numerical RTA created with operator clients delivers consistent well analysis in seconds to a few minutes, and importantly, was proven to work across their disparate geologies. Mathias Carlsen is a general manager at Whitson and has been at the center of the joint industry project from the beginning. Here, he helps explain what the industry should know about the RTA joint project and where it is heading. Assembling a Trifecta Carlsen, a reservoir engineering expert, described the overarching goal of the joint project not as a mission to discover a panacea for RTA but one designed to fill in its big gaps with some recent innovations. โWhat weโve been successful at through the joint industry project is getting the new tools ready so that the workflows can be easily used and in standardizing them for a wide range of wells found in every single unconventional basin in the world,โ he said.
- North America (1.00)
- Asia > Middle East > Saudi Arabia (0.54)
- Europe > Norway > Trรธndelag > Trondheim (0.24)
- South America > Argentina > Neuquรฉn Province > Neuquรฉn (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.82)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.54)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
Summary Natural fractures are of great significance to the management of petroleum resources, groundwater, and carbon sequestration. Given that many naturally fractured reservoirs have poorly connected fractures, the traditional dual-porosity model like Warren and Root's model is not reasonable for pressure transient analysis in these reservoirs. Therefore, the objective of this study is to develop a new discrete model (DM) in discretely fractured reservoirs based on a semianalytical approach. The DM comprises three domains: wellbore-connecting (WC) fractures and/or wellbore-isolating (WI) fractures, and matrix. The DM is verified by case studies with numerical simulators for four kinds of discretely fractured reservoirs with (1) WC fracture networks, (2) WI fracture networks, (3) WC and WI fractures, and (4) WI fractures. Results indicate that the pressure transient behaviors in discretely fractured reservoirs can be classified into three types: WC fracture networks, WC and WI fractures, and WI fracture (networks). The special flow regimes of WC fracture networks are fluid supply and pseudoboundary dominated flow. For WC and WI fractures, the special flow regimes are bilinear flow, linear flow, and isolated fracture effect. The early pseudoradial flow and isolated fracture effect ("V-shaped" or "dip") are the special flow regimes of WI fracture (networks), and they are similar to traditional dual-porosity models like the Warren and Root model. However, the source of "V-shaped" in DM is quite different from that in the Warren and Root model. This paper gives a new insight into the well testing in discretely fractured reservoirs. Introduction Well testing analysis is of great significance to performance forecasts and fracturing evaluations for petroleum resources, groundwater, and carbon sequestration in naturally fractured reservoirs. In those fractured reservoirs, discrete fractures are common features, as the formations are fractured by hydraulic fracturing, geological activities, thermal loading, and so on.
- Asia (0.67)
- North America > United States > Texas (0.46)
Analogy between Vertical Upward Cap Bubble and Horizontal Plug Flow
Arabi, Abderraouf (Direction Centrale Recherche et Dรฉveloppement, SONATRACH and Physicsโ Faculty, Laboratory of Theoretical and Applied Fluid Mechanics, LMFTA, University of Sciences and Technology Houari Boumedien (USTHB) (Corresponding author)) | Saidj, Faiza (FGMGP/LTPMP, University of Sciences and Technology Houari Boumediene (USTHB)) | Al-Sarkhi, Abdelsalam (Mechanical Engineering Department, King Fahd University of Petroleum and Minerals) | Azzi, Abdelwahid (FGMGP/LTPMP, University of Sciences and Technology Houari Boumediene (USTHB))
Summary The intermittent gas-liquid flow can be seen in both vertical upward and horizontal pipes. In a vertical pipe, the gas pockets of intermittent flow can be present as cap bubbles (cap bubble flow) or Taylor bubbles (slug flow), while in a horizontal configuration, the intermittent flow can be as plug or slug flows. Extensive literature survey has shown a lack of deep understanding of the difference between the vertical upward cap bubble and horizontal plug flow regimes. This paper explains the hydrodynamic similarities between vertical cap bubble flow and horizontal plug flow regimes. Moreover, the differences between the cap bubble and slug flow in vertical pipes are explained in detail. The study was carried out using a collected database from the open literature of different flow parameters. A comparison between the behavior of the void fraction, bubble structure velocity, slippage number, slug frequency, and slug length demonstrated the similarity between cap bubble and plug flows. It was also demonstrated, from the evolution of the void fraction, that the gas-to-liquid superficial velocities ratio plays a significant role in the cap bubble-to-slug flow transition. These results highlight the existence of an analogy between vertical cap bubble and horizontal plug flow. In addition, the difference between the flow structures and flow parameters behavior between cap bubble and slug flow, demonstrated in this study, highlights the need to differentiate between the two flow patterns.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.28)
- Europe > United Kingdom > England (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.88)
Abstract Objectives/Scope Transient well test analysis has been used to assess well condition and obtain reservoir parameters for over seventy years. At a time when Machine Learning (ML) and Artificial Intelligence (AI) are coming-of-age and may eventually replace well test interpreters, it is worth taking stock of the progress made in well test analysis since the major initial publications of the early 1950โs. Methods, Procedures, Process Major improvements in well test analysis since the early 1950's have occurred approximately 13 to 19 years apart, driven by the availability of both new types of data and new mathematical tools. Using a computer-generated data set of pressure and rate, we illustrate the evolution of well test analysis over the years: straight line methods of the early 1950's; log-log pressure plots of the late 1960's and early 1970's; formulation of an integrated methodology in the early 1980s; introduction of pressure-derivative analysis in 1983; derivation of a stable deconvolution algorithm in the early 2000's; and its current, successful extension to multiple interfering wells. Results, Observations, Conclusions Over the last seventy years, well test analysis has moved from just estimating well performance to becoming a very powerful tool for reservoir characterization. Novel/Additive Information Although the development of commercial software has been a factor in making practicing engineers aware of these improvements, acceptance has been slow: deconvolution has been developed twenty years ago and has been included in commercial software for the last fifteen years, yet is still not used in routine well test analysis. In addition, interest in well test analysis seems to be fading, which is in sharp contrast with its popularity in 1970's, as measured by the attendance to the well test analysis sessions in the annual ATCE meetings. It is hoped that the new advances in ML and AI will reverse this trend and reinstate well test analysis as a major reservoir characterization tool.
Analytical Representation of Flows Due to Arbitrary Distributions of Singularities for Steady Motion of Ships in Finite Water Depth
Wu, Huiyu (State Key Laboratory of Ocean Engineering, School of Naval Architecture, Ocean & Civil Engineering, Shanghai Jiao Tong University) | Zhu, Ren-Chuan (State Key Laboratory of Ocean Engineering, School of Naval Architecture, Ocean & Civil Engineering, Shanghai Jiao Tong University) | He, Jiayi (State Key Laboratory of Ocean Engineering, School of Naval Architecture, Ocean & Civil Engineering, Shanghai Jiao Tong University)
ABSTRACT Flow around a ship that advances at a constant speed in calm water of finite depth is considered within the usual framework of the Green-function and boundary-integral method associated with potential-flow theory. This method requires accurate and efficient evaluation of flows created by distributions of singularities over panels used to approximate the ship hull surface. This basic element of the Green-function method is considered for steady motion of ships in the subcritical and supercritical flow regimes. An analytical representation of the flow created by a general distribution of singularities over a hull-surface panel is given. This flow-representation is based on the Fourier-Kochin approach, in which space-integration over the panel is performed first and Fourier-integration is performed subsequently, unlike the common approach in which the Green function (defined via a Fourier integration) is evaluated first and subsequently integrated over the panel. The analytical and numerical complexities associated with the numerical evaluation and subsequent panel integration of the Green function are then avoided in the Fourier-Kochin approach. The analytical flow-representation provides a smooth decomposition of free-surface effects into waves and a non-oscillatory local flow. Illustrative numerical applications to the flow potentials and velocities associated with a typical distribution of sources over a panel show that the flow-representation given in the study is well suited for accurate and efficient numerical evaluation. INTRODUCTION Flow around a ship that advances at a constant speed in calm water of uniform finite depth is considered within the classical framework of linear potential-flow theory and the related Green-function and boundary-integral method in which the Green function satisfies the linearized Kelvin-Michell free-surface boundary condition. This theoretical frame-work is realistic and suited for routine practical applications. Indeed, in deep water, this theory has been shown to yield predictions of the wave drag, the hydrodynamic lift and pitch-moment (and the resulting sinkage and trim), as well as the wave profile along a ship hull, that are sufficiently accurate for practical purposes within a broad range of Froude numbers (Noblesse et al., 2013; Huang et al., 2013; Zhang et al., 2014; Ma et al., 2017, 2018). In addition, numerical methods based on potential-flow theory are well suited for ship design and hull-form optimization, as is largely demonstrated in e.g. (Yang et al., 2014; Huang et al., 2016; Huang & Yang, 2016; Yang & Huang, 2016; Zha et al., 2021).
- Energy > Oil & Gas > Upstream (1.00)
- Transportation > Marine (0.89)
Flow Pattern, Pressure Gradient Relationship of Gas Kick Under Dynamic Conditions
Obi, Chinemerem Edmond (Texas A&M University) | Falola, Yusuf (Texas A&M University) | Manikonda, Kaushik (Texas A&M University) | Hasan, Abu Rashid (Texas A&M University) | Rahman, Mohammad Azizur (Texas A&M University, Qatar)
Abstract The warning signs of possible kick during drilling operation can either be primary (flow rate increase and pit gain) or secondary (drilling break, pump pressure decrease, and stroke increase). Likewise, the drillers rely on the pressure readings at the surface to have an insight into in-situ downhole conditions while drilling. The surface pressure reading is always available and accessible. However, understanding or interpretation of this data is often ambiguous. This study analyses significant kick symptoms in the wellbore annulus while drilling/circulating. We have tied several observed annular flow patterns to the measured pressure, and flow data from the surface during water-air, and water-carbon dioxide complex flow. This is based on experiments using a 140 ft high tower lab, with a hydraulic diameter of about 3 in. The experiments have been carried out under dynamic conditions to simulate circulating drilling mud from the wellbore. We used both supervised and unsupervised learning techniques for flow regime identification and kick prognosis. These include an Artificial Neural Network (ANN), Support Vector Machine (SVM), K-Nearest Neighbor (KNN), Decision Trees, K-Means and Agglomerative Clustering. All the machine learning techniques used in this work made excellent predictions with accuracy greater than or equal to 90%. For the supervised learning, the decision tree gave the overall best results with an accuracy of 96% for air-influx cases and 98% for carbon dioxide influx cases. For the unsupervised learning, K-Means clustering was the best, with Silhouette scores ranging from about 0.7 to 0.8 for the rate data clusters, and 0.4 to 0.5 for pressure data clusters. The mass rate per hydraulic diameter and the mixture viscosity also resulted in the best type of clusters. This is because this approach accounts for the fluid properties, flow rate, and flow geometry. The estimation of the influx size and type is highly dependent on the duration of kick and the overbalance kick influx pressure. The quantity of the mass influx significantly controls the flow pattern, pressure losses, and pressure gradient as the kick migrates to the surface. The resulting turbulent flow after the initial kick (After Taylor bubble flow) varied with duration of kick, average liquid flow rate, influx type, and drilling scenario. Surface pressure readings can be tied to flow regime to better visualize well control approach while drilling. This works provides an alternative and easily accessible primary kick detection tool for drillers based on measured pressure responses at the surface. It also relates this pressure data to certain annular flow regime patterns to better tell the downhole story while drilling.
- North America > United States (1.00)
- Asia > Middle East (0.68)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Support Vector Machines (0.88)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Clustering (0.88)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Nearest Neighbor Methods (0.54)
Abstract Liquid-assisted gas-lift process (LAGL), a variation of conventional gas lift, is a relatively new technique to improve the productivity of existing wells suffering from liquid loading. Its versatility is especially attractive because modern wells tend to be deeper, often with long horizontal sections, as shown by the examples from offshore and unconventional resources developments. By conducting transient computer simulations in various scenarios (i.e., a wide range of injection conditions for shallow and deep wells), this study aims to gain the fundamental knowledges associated with LAGL and learn how to apply them optimally in the field applications - unloading liquids in the producing wells and, at the same time, reducing the maximum injection pressure (Pinj-max) required. After determining model parameters from the simulation fit to experimental data and extending the simulations into a wide range of conditions, this study shows the following major findings. First, adding water in the injection stream during LAGL process does not always guarantee a reduction in Pinj-max. Instead, the results support that there is a certain range of injection-condition window (in terms of gas and liquid flowrates (Qg and Qw)) within which the process can effectively reduce the maximum injection pressure (Pinj-max). Second, the presence of such a window associated with a multi-valued problem is caused by the complex multiphase flow behavior, which coincides with the change in flow regimes (i.e., transitioning from mist/annular flow to slug flow). Third, applying the injection condition within the window in field-scale trials may not be necessarily straight forward because the pressure and liquid holdup responses sometimes show oscillatory behaviors (whether cyclic or chaotic) during the process. These oscillatory behaviors occur more easily in deeper wells in which the system allows more time for the injected gas and liquid mixture to get segregated during the downward flow in the annulus. The use of pressure and liquid holdup contours, as implemented in this study, is believed to be a useful means of planning for the LAGL treatments in the field.
- Asia (0.67)
- North America > United States > Oklahoma (0.28)
- North America > United States > Colorado (0.28)
- North America > United States > Texas (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)