Calibration of Permeability Vertical Profile with Regard to Well Production Data (Russian)

2010 ◽  
Author(s):  
Mars Magnavievich Khasanov ◽  
Konstantin Toropov ◽  
Alexander Aleksevich Lubnin
Keyword(s):  
Vertical Profile ◽  
Production Data ◽  
Well Production

Diagnostic Plots for Production Decline During the Transition of Oil Field Development From Depletion to Water Injection

2021 ◽  
Author(s):  
Vil Syrtlanov ◽  
Yury Golovatskiy ◽  
Ivan Ishimov
Keyword(s):  
Water Injection ◽  
Simulation Models ◽  
Oil Field ◽  
Production Data ◽  
Oil Reservoir ◽  
Field Development ◽  
Well Production ◽  
Diagnostic Plots ◽  
Oil Field Development ◽  
Analytical Approaches

Abstract In this paper the simplified way is proposed for predicting the dynamics of liquid production and estimating the parameters of the oil reservoir using diagnostic curves, which are a generalization of analytical approaches, partially compared with the results of calculations on 3D simulation models and with actual well production data.

Analysis of Boundary-Dominated Gas Well Production Data

2019 ◽  
Author(s):  
Shaibu Mohammed ◽  
Prosper Anumah ◽  
Justice Sarkodie-Kyeremeh ◽  
Anthony Morgan ◽  
Emmanuel Acheaw
Keyword(s):  
Production Data ◽  
Gas Well ◽  
Well Production

IMAGING ADDITIONAL OIL AND GAS RESERVES, INTEGRATING WELL PRODUCTION DATA AND 3D SEISMIC AVO CLASSIFICATION TO IMAGE REMAINING OIL AND GAS RESERVES—A CASE STUDY ON THE NGATORO FIELD, TARANAKI, NEW ZEALAND

2001 ◽  
Vol 41 (1) ◽  
pp. 679
Author(s):  
S. Reymond ◽  
E. Matthews ◽  
B. Sissons
Keyword(s):  
New Zealand ◽  
Oil And Gas ◽  
Seismic Facies ◽  
Bright Spot ◽  
Production Data ◽  
3D Seismic ◽  
Reservoir Model ◽  
Reservoir Properties ◽  
Well Production

This case study illustrates how 3D generalised inversion of seismic facies for reservoir parameters can be successfully applied to image and laterally predict reservoir parameters in laterally discontinuous turbiditic depositional environment where hydrocarbon pools are located in complex combined stratigraphic-structural traps. Such conditions mean that structural mapping is inadequate to define traps and to estimate reserves in place. Conventional seismic amplitude analysis has been used to aid definition but was not sufficient to guarantee presence of economic hydrocarbons in potential reservoir pools. The Ngatoro Field in Taranaki, New Zealand has been producing for nine years. Currently the field is producing 1,000 bopd from seven wells and at three surface locations down from a peak of over 1,500 bopd. The field production stations have been analysed using new techniques in 3D seismic imaging to locate bypassed oils and identify undrained pools. To define the objectives of the study, three questions were asked:Can we image reservoir pools in a complex stratigraphic and structural environment where conventional grid-based interpretation is not applicable due to lack of lateral continuity in reservoir properties?Can we distinguish fluids within each reservoir pools?Can we extrapolate reservoir parameters observed at drilled locations to the entire field using 3D seismic data to build a 3D reservoir model?Using new 3D seismic attributes such as bright spot indicators, attenuation and edge enhancing volumes coupled with 6 AVO (Amplitude Versus Offset) volumes integrated into a single class cube of reservoir properties, made the mapping of reservoir pools possible over the entire data set. In addition, four fluid types, as observed in more than 20 reservoir pools were validated by final inverted results to allow lateral prediction of fluid contents in un-drilled reservoir targets. Well production data and 3D seismic inverted volume were later integrated to build a 3D reservoir model to support updated volumetrics reserves computation and to define additional targets for exploration drilling, additional well planning and to define a water injection plan for pools already in production.

Joint Pressure and Production Analysis to Understand Inter- and Intra-Zone Well Interference: A Midland Basin Case Study

2021 ◽  
Author(s):  
Qin Ji ◽  
Geoff Vernon ◽  
Juan Mata ◽  
Shannon Klier ◽  
Matthew Perry ◽  
...  
Keyword(s):  
Surface Pressure ◽  
Production Data ◽  
Well Performance ◽  
Pressure Data ◽  
Midland Basin ◽  
Well Production ◽  
Interference Test ◽  
The Impact ◽  
Fracture Growth ◽  
Pressure Analysis

Abstract This paper demonstrates how to use pressure data from offset wells to assess fracture growth and evolution through each stage by quantifying the impacts of nearby parent well depletion, completion design, and formation. Production data is analyzed to understand the correlation between fracture geometries, well interactions, and well performance. The dataset in this project includes three child wells and one parent well, landed within two targets of the Wolfcamp B reservoir in the Midland Basin. The following workflow helped the operator understand the completion design effectiveness and its impact to production:Parent well pressure analysis during completionIsolated stage offset pressure analysis during completionOne-month initial production analysis followed by one month shut-inPressure interference test: sequentially bringing wells back onlineProduction data comparison before and after shut-in period An integrated analysis of surface pressure data acquired from parent and offset child wells during completions provides an understanding of how hydraulic dimensions of each fracture stage are affected by fluid volume, proppant amount, frac stage order of operations, and nearby parent well depletion. Production data from all wells was analyzed to determine the impact of depletion on child well performance and to investigate the effects of varying completion designs. A pressure interference test based on Chow Pressure Group was also performed to further examine the connectivity between wells, both inter- and intra-zone. Surface pressure data recorded from isolated stages in the offset child wells during completions was used to resolve geometries and growth rates of the stimulated fractures. Asymmetric fracture growth, which preferentially propagates toward the depleted rock volume around the parent well, was identified at the heel of the child well closest to the parent. Fracture geometries of various child well stage groups were analyzed to determine the effectiveness of different completion designs and the impact of in situ formation properties. Analysis of parent well surface pressure data indicates that changing the completion design effectively reduced the magnitude of Fracture Driven Interactions (FDIs) between child and parent wells. Child well production was negatively impacted in the wells where the fracture boundary overlapped with the parent well depleted volume in the same formation zone. This study combines pressure and production analyses to better understand inter- and intra-zone interference between wells. The demonstrated workflow offers a very cost-effective approach to studying well interference. Observing and understanding the factors that drive fracture growth behavior enables better decision-making during completion design planning, mitigation of parent-child communication, and enhancement of offset well production.

Production-Data Analysis of Single-Phase (Gas) Coalbed-Methane Wells

2007 ◽  
Vol 10 (03) ◽  
pp. 312-331 ◽  
Author(s):  
Christopher R. Clarkson ◽  
R. Marc Bustin ◽  
John P. Seidle
Keyword(s):  
Coalbed Methane ◽  
Single Phase ◽  
Material Balance ◽  
Production Data ◽  
Reservoir Properties ◽  
Type Curve ◽  
Well Production ◽  
Single Well ◽  
Permeability Anisotropy ◽  
Cbm Production

Summary Coalbed-methane (CBM) reservoirs commonly exhibit two-phase-flow (gas plus water) characteristics; however, commercial CBM production is possible from single-phase (gas) coal reservoirs, as demonstrated by the recent development of the Horseshoe Canyon coals of western Canada. Commercial single-phase CBM production also occurs in some areas of the low-productivity Fruitland Coal, south-southwest of the high-productivity Fruitland Coal Fairway in the San Juan basin, and in other CBM-producing basins of the continental United States. Production data of single-phase coal reservoirs may be analyzed with techniques commonly applied to conventional reservoirs. Complicating application, however, is the unique nature of CBM reservoirs; coal gas-storage and -transport mechanisms differ substantially from conventional reservoirs. Single-phase CBM reservoirs may also display complex reservoir behavior such as multilayer characteristics, dual-porosity effects, and permeability anisotropy. The current work illustrates how single-well production-data-analysis (PDA) techniques, such as type curve, flowing material balance (FMB), and pressure-transient (PT) analysis, may be altered to analyze single-phase CBM wells. Examples of how reservoir inputs to the PDA techniques and subsequent calculations are modified to account for CBM-reservoir behavior are given. This paper demonstrates, by simulated and field examples, that reasonable reservoir and stimulation estimates can be obtained from PDA of CBM reservoirs only if appropriate reservoir inputs (i.e., desorption compressibility, fracture porosity) are used in the analysis. As the field examples demonstrate, type-curve, FMB, and PT analysis methods for PDA are not used in isolation for reservoir-property estimation, but rather as a starting point for single-well and multiwell reservoir simulation, which is then used to history match and forecast CBM-well production (e.g., for reserves assignment). CBM reservoirs have the potential for permeability anisotropy because of their naturally fractured nature, which may complicate PDA. To study the effects of permeability anisotropy upon production, a 2D, single-phase, numerical CBM-reservoir simulator was constructed to simulate single-well production assuming various permeability-anisotropy ratios. Only large permeability ratios (>16:1) appear to have a significant effect upon single-well production characteristics. Multilayer reservoir characteristics may also be observed with CBM reservoirs because of vertical heterogeneity, or in cases where the coals are commingled with conventional (sandstone) reservoirs. In these cases, the type-curve, FMB, and PT analysis techniques are difficult to apply with confidence. Methods and tools for analyzing multilayer CBM (plus sand) reservoirs are presented. Using simulated and field examples, it is demonstrated that unique reservoir properties may be assigned to individual layers from commingled (multilayer) production in the simple two-layer case. Introduction Commercial single-phase (gas) CBM production has been demonstrated recently in the Horseshoe Canyon coals of western Canada (Bastian et al. 2005) and previously in various basins in the US; there is currently a need for advanced PDA techniques to assist with evaluation of these reservoirs. Over the past several decades, significant advances have been made in PDA of conventional oil and gas reservoirs [select references include Fetkovich (1980), Fetkovich et al. (1987), Carter (1985), Fraim and Wattenbarger (1987), Blasingame et al. (1989, 1991), Palacio and Blasingame (1993), Fetkovich et al. (1996), Agarwal et al. (1999), and Mattar and Anderson (2003)]. These modern methods have greatly enhanced the engineers' ability to obtain quantitative information about reservoir properties and stimulation/damage from data that are gathered routinely during the producing life of a well, such as production data and, in some instances, flowing pressure information. The information that may be obtained from detailed PDA includes oil or gas in place (GIP), permeability-thickness product (kh), and skin (s), and this can be used to supplement information obtained from other sources such as PT analysis, material balance, and reservoir simulation.

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