Conversion of Point-After-Point Gas Well Test Results To Equivalent Isochronal Test Results

1985 ◽  
pp. 201-208
Author(s):  
Mihir K. Sinha ◽  
Larry R. Padgett
Keyword(s):  
Test Results ◽  
Well Test ◽  
Gas Well

Evaluation of Well-Test Results and the Potential for Basin-Center Gas in the Colulmbia Basin, Central Washington

Data Series ◽  
2008 ◽  
Author(s):  
Matthew Wilson ◽  
Thaddeus S. Dyman ◽  
Steven M. Condon
Keyword(s):  
Test Results ◽  
Well Test

A CASE STUDY OF A CARBON DIOXIDE WELL TEST

2007 ◽  
Vol 47 (1) ◽  
pp. 239
Author(s):  
J.Q. Xu ◽  
G. Weir ◽  
L. Paterson ◽  
I. Black ◽  
S. Sharma
Keyword(s):  
Carbon Dioxide ◽  
Natural Gas ◽  
Large Scale ◽  
Surface Flow ◽  
Phase Changes ◽  
Co2 Production ◽  
Research Centre ◽  
Well Test ◽  
Cooperative Research ◽  
Gas Well

This paper reports on the planning, procedure, results and analysis of a carbon dioxide (CO2) well test performed on Buttress–1, a well located in the Otway Basin, Victoria, Australia. A large-scale pilot study of CO2 sequestration is planned by the Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) in this area, which will involve, inter alia, taking CO2 from the Buttress reservoir and injecting it into a nearby depleted gas field. Understanding the production characteristics of this well is important to the success of this pilot, which forms part of a more extensive study to establish viable means to mitigate CO2 emissions to the atmosphere. This general backdrop forms the motivation for this study.Testing comprised of a standard suite of draw-downs and build-ups to determine reservoir/well characteristics, such as the well deliverability, the non-Darcy skin coefficient and the average reservoir permeability and volume.Compared to the wealth of experience developed over many years in testing oil and gas wells, the collective experience in CO2 well testing is extremely limited. The distinguishing features between this test and those of a typical natural gas well test need to be emphasised. Although, in general, flow testing a CO2 well should be similar to testing a natural gas well, differences in the thermodynamic properties of CO2 affect the analysis of the well test considerably. In particular, the non-Darcy skin effect is more pronounced and the wellbore and surface flow can involve dramatic phase changes, such as the formation of ice. Also, since CO2 is more compressible than a typical natural gas, the accurate measurement of the flow rate becomes more challenging. It is also apparent that the use of pseudo pressure, as opposed to simpler methods of dealing with the pressure dependency of key properties, is essential to the successful analysis of the pressure response to the CO2 production.

CSG well testing—Santos' experience in Queensland

2013 ◽  
Vol 53 (1) ◽  
pp. 227
Author(s):  
Czek Hoong Tan ◽  
Guncel Demircan ◽  
Mathias Satyagraha
Keyword(s):  
Radial Flow ◽  
Test Methods ◽  
Well Testing ◽  
Test Results ◽  
Well Test ◽  
Well Performance ◽  
Validity Of Results ◽  
Transient Behaviour ◽  
Key Factor ◽  
Primary Porosity

Permeability of the cleat system is a key factor controlling the productivity of CSG reservoirs and, therefore, the commerciality of development projects. Well testing is routinely used to provide representative values of coal permeability. The authors’ experience has shown pressure transient behaviour in coal reservoirs to be similar to those in primary porosity systems, with pseudo radial flow frequently observed, and the dual-porosity signature largely absent. Despite the authors’ best efforts in test design, large permeability variation and extremely high skin factors have been seen. The authors have run variations of drill stem tests (DSTs), injection tests, and wireline tests to understand the dependency of results to test methods, and the validity of results obtained. Pertinent examples of each type of test are discussed. Finally, recommendations to reconcile well test results to actual well performance are presented.

scholarly journals Experimental Study and Estimation of Groundwater Fluctuation and Ground Settlement due to Dewatering in a Coastal Shallow Confined Aquifer

2019 ◽  
Vol 7 (3) ◽  
pp. 58 ◽  
Author(s):  
Jiong Li ◽  
Mingguang Li ◽  
Lulu Zhang ◽  
Hui Chen ◽  
Xiaohe Xia ◽  
...  
Keyword(s):  
High Speed ◽  
Prediction Method ◽  
Burial Depth ◽  
Confined Aquifer ◽  
Test Results ◽  
Well Test ◽  
Ground Settlement ◽  
Empirical Prediction ◽  
Soil Settlement ◽  
Groundwater Fluctuations

The coastal micro-confined aquifer (MCA) in Shanghai is characterized by shallow burial depth, high artesian head, and discontinuous distribution. It has a significant influence on underground space development, especially where the MCA is directly connected with deep confined aquifers. In this paper, a series of pumping well tests were conducted in the MCA located in such area to investigate the dewatering-induced groundwater fluctuations and stratum deformation. In addition, a numerical method is proposed for the estimation of hydraulic parameter, and an empirical prediction method is developed for dewatering-induced ground settlement. Test results show that groundwater drawdowns and soil settlement can be observed not only in MCA but also in the aquifers underneath it. This indicates that there is a close hydraulic connection among each aquifer. Moreover, the distributions and development of soil settlement at various depths are parallel to those of groundwater drawdowns in most areas of the test site except the vicinity of pumping wells, where collapse-induced subsidence due to high-speed flow may occur. Furthermore, the largest deformation usually occurs at the top of the pumping aquifer instead of the ground surface, because the top layer is expanded due to the stress arch formed in it. Finally, the proposed methods are validated to be feasible according to the pumping well test results and can be employed to investigate the responses of groundwater fluctuations and stratum deformations due to dewatering in MCA.

scholarly journals Flow description of gas well in basement granite reservoir from well test analysis

2019 ◽  
Vol 1402 ◽  
pp. 022062
Author(s):  
H K Oetomo ◽  
R Sitaresmi ◽  
D P Laksana
Keyword(s):  
Well Test ◽  
Well Test Analysis ◽  
Test Analysis ◽  
Gas Well

Postfracturlng Gas-Well-Test Analysis Using Buildup Type Curves

1991 ◽  
Vol 6 (03) ◽  
pp. 393-400
Author(s):  
D.M. Walsh ◽  
K.H. Leung
Keyword(s):  
Well Test ◽  
Well Test Analysis ◽  
Test Analysis ◽  
Gas Well ◽  
Type Curves

Determining Average Reservoir Pressure From Pressure Buildup Tests

1974 ◽  
Vol 14 (01) ◽  
pp. 55-62 ◽  
Author(s):  
Hossein Kazemi
Keyword(s):  
Oil Reservoirs ◽  
Reservoir Engineering ◽  
Reservoir Pressure ◽  
Well Test ◽  
Gas Well ◽  
Pressure Buildup ◽  
Line Section ◽  
Straight Line ◽  
Buildup Curve

Abstract Two simple and equivalent procedures are suggested for improving the calculated average reservoir pressure from pressure buildup tests of liquid or gas wells in developed reservoirs. These procedures are particularly useful in gas well test procedures are particularly useful in gas well test analysis, irrespective of gas composition, in reservoirs with pressure-dependent permeability and porosity, and in oil reservoirs where substantial gas porosity, and in oil reservoirs where substantial gas saturation has been developed. A knowledge of the long-term production history is definitely helpful in providing proper insight in the reservoir engineering providing proper insight in the reservoir engineering aspects of a reservoir, but such long-term production histories need not be known in applying the suggested procedures to pressure buildup analysis. Introduction For analyzing pressure buildup data with constant flow rate before shut-in, there are two plotting procedures that are used the most: the procedures that are used the most: the Miller-Dyes-Hutchinson (MDH) plot and the Horner plot. The MDH plot is a plot of p vs log Deltat, whereas the Horner plot is a plot of p vs log [(t + Deltat)/Deltat]. Deltat is the shut-in time and t is a pseudoproduction time equal to the ratio of total produced fluid to last stabilized flow rate before shut-in. This method was first used by Theis in the water industry. Miller-Dyes-Hutchinson presented a method for calculating the average reservoir pressure, T, in in 1950. This method requires pseudosteady state before shut-in and was at first restricted to a circular reservoir with a centrally located well. Pitzer extended the method to include other Pitzer extended the method to include other geometries. Much later, Dietz developed a simpler interpretation scheme using the same MDH plot: p is read on the extrapolated straight-line section of the pressure buildup curve at shut-in time, Deltat,(1) where C is the shape factor for the particular drainage area geometry and the well location; values for C are tabulated in Refs. 5 and 13. For a circular drainage area with a centrally located well, C = 31.6, and for a square, C = 30.9.Horner presented another approach, which depended on the knowledge of the initial reservoir pressure, pi. This method also was first developed pressure, pi. This method also was first developed for a centrally located well in a circular reservoir.Matthews-Brons-Hazebroek (MBH) introduced another average reservoir pressure determination technique, which has been used more often than other methods: first a Horner plot is made; then the proper straight-line section of the buildup curve is proper straight-line section of the buildup curve is extrapolated to [(t + Deltat)/Deltat] = 1 (this intercept is denoted p*); finally, p is calculated from(2) m is the absolute value of the slope of the straightline section of the Horner plot:(3) pDMBH (tDA) is the MBH dimensionless pressure pDMBH (tDA) is the MBH dimensionless pressure at tDA, and tDA is the dimensionless time:(4) tp k a pseudoproduction time in hours:(5) PDMBH tDA) for different geometries and different PDMBH tDA) for different geometries and different well locations are given in Refs. 6 and 13.The second term on the right-hand side of Eq. 2 is a correction term for finite reservoirs that is based on material balance. Thus, for an infinite reservoir, p = pi = p*, where pi is the initial reservoir pressure. SPEJ P. 55

Determination of Formation Properties From Stabilized and Unstabilized Gas-Well-Test Data

2000 ◽  
Author(s):  
Omer Inanc Tureyen ◽  
Abdurrahman Satman ◽  
Mustafa Onur
Keyword(s):  
Test Data ◽  
Well Test ◽  
Gas Well
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