Best Practices in DFIT Interpretation: Comparative Analysis of 62 DFITs from Nine Different Shale Plays

2022 ◽  
Author(s):  
Mark Mcclure ◽  
Garrett Fowler ◽  
Matteo Picone
Keyword(s):  
Pressure Drop ◽  
Pore Pressure ◽  
Time Pressure ◽  
Early Time ◽  
Horizontal Wells ◽  
Late Time ◽  
Fracture Length ◽  
Well Spacing ◽  
Net Pressure ◽  
The Difference

Abstract In URTeC-123-2019, a group of operators and service companies presented a step-by-step procedure for interpretation of diagnostic fracture injection tests (DFITs). The procedure has now been applied on a wide variety of data across North and South America. This paper statistically summarizes results from 62 of these DFITs, contributed by ten operators spanning nine different shale plays. URTeC-123-2019 made several novel claims, which are tested and validated in this paper. We find that: (1) a ‘compliance method’ closure signature is apparent in the significant majority of DFITs; (2) in horizontal wells, early time pressure drop due to near-wellbore/midfield tortuosity is substantial and varies greatly, from 500 to 6000+ psi; (3) in vertical wells, early-time pressure drop is far weaker; this supports the interpretation that early- time pressure drop in horizontal wells is caused by near-wellbore/midfield tortuosity from transverse fracture propagation; (4) the (not recommended) tangent method of estimating closure yields Shmin estimates that are 100-1000+ psi lower than the estimate from the (recommended) compliance method; the implied net pressure values are 2.5x higher on average and up to 5-6x higher; (5) as predicted by theory, the difference between the tangent and compliance stress and net pressure estimates increases in formations with greater difference between Shmin and pore pressure; (6) the h-function and G-function methods allow permeability to be estimated from truncated data that never reaches late-time impulse flow; comparison shows that they give results that are close to the permeability estimates from impulse linear flow; (7) false radial flow signatures occur in the significant majority of gas shale DFITs, and are rare in oil shale DFITs; (8) if false radial signatures are used to estimate permeability, they tend to overestimate permeability, often by 100x or more; (9) the holistic-method permeability correlation overestimates permeability by 10-1000x; (10) in tests that do not reach late-time impulse transients, it is reasonable to make an approximate pore pressure estimate by extrapolating the pressure from the peak in t*dP/dt using a scaling of t^(-1/2) in oil shales and t^(3/4) in gas shales. The findings have direct practical implications for operators. Accurate permeability estimates are needed for calculating effective fracture length and for optimizing well spacing and frac design. Accurate stress estimation is fundamental to hydraulic fracture design and other geomechanics applications.

scholarly journals Cost Implications of Comorbidity for Autologous Stem Cell Transplantation in Elderly Patients with Multiple Myeloma Using SEER-Medicare

2016 ◽  
Vol 2016 ◽  
pp. 1-6 ◽  
Author(s):  
Gunjan L. Shah ◽  
Aaron Winn ◽  
Pei-Jung Lin ◽  
Andreas Klein ◽  
Kellie A. Sprague ◽  
...  
Keyword(s):  
Older Patients ◽  
Early Period ◽  
Early Time ◽  
Cost Of Care ◽  
Late Time ◽  
Time Period ◽  
Comorbidity Burden ◽  
Impact On Survival ◽  
The Difference ◽  
Early Time Period

Comorbidity is more common in older patients and can increase the cost of care by increasing toxicity. Using the SEER-Medicare database from 2000 to 2007, we examined the costs and life-year benefit of Auto-HSCT for MM patients over the age of 65 by evaluating the difference over time relative to comorbidity burden. One hundred ten patients had an Auto-HSCT in the early time period (2000–2003) and 160 in the late time period (2004–2007). Patients were divided by a Charlson Comorbidity Index (CCI) of 0 or greater than 1 (CCI1+). Median overall survival was 53.5 months for the late time period patients compared to 40.3 months for the early time period patients (p=0.031). Median costs for CCI0 versus CCI1+ in the early period were, respectively, $70,900 versus $72,000 (100 d); $86,100 versus $98,300 (1 yr); and $139,200 versus $195,300 (3 yrs). Median costs for late period were, respectively, $58,400 versus $60,400 (100 d); $86,300 versus $77,700 (1 yr); and $124,400 versus $110,900 (3 yrs). Comorbidity had a significant impact on survival and cost among early time period patients but not among late time period patients. Therefore, older patients with some comorbidities can be considered for Auto-HSCT depending on clinical circumstances.

INFLUENCE OF TIDAL PHENOMENA ON INTERPRETATION OF PRESSURE BUIILD-UP AND PULSE TESTS

1976 ◽  
Vol 16 (1) ◽  
pp. 99 ◽  
Author(s):  
A.K. Khurana
Keyword(s):  
Time Pressure ◽  
Pressure Gauge ◽  
Early Time ◽  
Late Time ◽  
Time Lags ◽  
Pressure Oscillations ◽  
Hole Pressure ◽  
Bottom Hole Pressure ◽  
Bottom Hole ◽  
Gippsland Basin

Bottom-hole pressure tests conducted in the Kingfish oil reservoir (located in Gippsland Basin - Offshore Victoria) during 1974 and 1975 using a high sensitivity surface recording electronic bottom-hole pressure gauge indicated the presence of sinusoidal pressure oscillations in the reservor. The oscillations are of the order of 0.1 psi in amplitude and their frequency suggests that they are in some way related to tidal phenomena.Although the oscillations do not affect production, they do influence interpretation of pressure build-up and pulse tests. Interpretations of both late time pressure build-up behaviour and pulse tests of small response magnitude and long time lags are considered to be particularly susceptible to errors due to these oscillations if they are not recognized and corrected for. Interpretations of early time pressure build-up data and pulse tests of definite response and relatively short time lags are not regarded as being significantly affected.The physical mechanism causing these pressure oscillations in the reservoirs is not known. However, one of the various possible hypotheses is that the Latrobe Formation sands could be outcropping on the ocean floor at abyssal depths southeast of Kingfish and that the pressure transients generated by changes in the hydrostatic head due to surfate tides are transmitted hydraulically to the reservoir. If this hypothesis is proved to be valid it could influence pressure performance predictions of Gippsland Basin reservoirs.

Finite Horizontal Well in a Uniform-Thickness Reservoir Crossing a Natural Fracture Normally

SPE Journal ◽  
2013 ◽  
Vol 18 (05) ◽  
pp. 982-992 ◽  
Author(s):  
Michael Prats ◽  
R.. Raghavan
Keyword(s):  
Horizontal Well ◽  
Time Pressure ◽  
Finite Thickness ◽  
Early Time ◽  
Natural Fracture ◽  
Late Time ◽  
Arithmetic Average ◽  
Analytic Expressions ◽  
Accelerate Convergence ◽  
Instantaneous Source

Summary The instantaneous source solutions of Prats and Raghavan (2012) and the method of images are used to develop analytic expressions for the pressure distribution in a three-region composite reservoir of finite thickness produced by a finite-length horizontal well that is oriented perpindicular to the interfaces. The composite reservoir is assumed to be infinite in its lateral extents; the outer regions represent the reservoir, and the central region represents a thin natural fracture of relatively high permeability. In most of the cases considered, the well is completed in all three zones. The computational scheme is shown to be both viable and robust. The Shanks (1955) transformation is used to accelerate convergence. Pressure traces are logarithmic in time at early and late times for any well configuration examined here. Early-time pressure characteristics are similar to those discussed in Prats and Raghavan (2012). The duration of the early semilogarithmic responses is mediated not only by the presence of the higher-permeability natural fracture, as before, but also now by the interaction of the upper and lower boundaries with the well. Late-time semilogarithmic responses, however, are distinctly different. Their slope is inversely proportional to the product of the formation thickness and the arithmetic average permeability of the two regions that sandwich the fracture. This result holds even when the well does not cross the natural fracture. We expect this conclusion to apply to a composite system consisting of more than three regions. Observations concerning the late-time slope represent the central finding of this study. A relationship is given for the late-time performance of any horizontal well in terms of that of a vertical well with a constant pseudoskin. Pseudoskin equivalents are reported for all cases discussed.

Estimation of Solubility and Diffusivity of Gases in Heavy Oils by Use of Late-Time Pressure-Decay Data: An Analytical/Graphical Approach

SPE Journal ◽  
2015 ◽  
Vol 20 (04) ◽  
pp. 717-728 ◽  
Author(s):  
Francisco J. Pacheco-Roman ◽  
S. Hossein Hejazi
Keyword(s):  
Diffusion Coefficient ◽  
Gas Phase ◽  
Time Pressure ◽  
Early Time ◽  
Late Time ◽  
Heavy Oils ◽  
Time Data ◽  
Henry's Constant ◽  
Pressure Decay ◽  
Phase Pressure

Summary Solubility and diffusivity of gases in heavy oils, quantified by Henry's constant (Hij) and the diffusion coefficient (D), respectively, are essential properties for the design of recovery processes that require the injection of gas or vapor solvents into the reservoir. Data, obtained from various experimental procedures such as the pressure-decay technique (PDT), are used to estimate these two parameters. The PDT uses a pressure/volume/temperature (PVT) cell where the gas-phase pressure declines as gas diffuses into heavy oil following an early- and a late-time regime. Current approaches to analyze data from the conventional PDT are either graphical techniques based on early-time data or full numerical simulation. Early-time data, when the diffusing gas has not reached the bottom of the PVT cell, do not provide enough information to simultaneously estimate both the diffusion coefficient and Henry's constant. Hence, existing graphical procedures are limited to diffusion-coefficient estimation. In this paper, we propose a novel graphical technique to estimate the diffusion coefficient and Henry's constant by use of the late-time data from pressure-decay experiments. Our method is derived from the modeling of gas-phase pressure decay by use of Fick's second law and gas-phase mass-balance equations. We use the integral method to provide an approximate analytical solution to the set of equations. In addition, by use of the resultant solution, we develop a simple graphical method to directly estimate both the diffusion coefficient and Henry's constant. The estimated parameters through the proposed technique for methane/bitumen and carbon dioxide/bitumen experiments are in close agreement with those reported in the literature.

Flow Coefficient Evaluation of Poppet Valves Used in Reciprocating Compressors for LDPE

2008 ◽  
Author(s):  
Enzo Giacomelli ◽  
Massimo Schiavone ◽  
Fabio Manfrone ◽  
Andrea Raggi
Keyword(s):  
Pressure Drop ◽  
Time Pressure ◽  
Experimental Tests ◽  
Operating Conditions ◽  
Flow Coefficient ◽  
Operating Life ◽  
High Fatigue ◽  
Strongly Connected ◽  
And Performance ◽  
Poppet Valves

Poppet valves have been used for a long time for very high pressure reciprocating compressors, as for example in the case of Low Density Polyethylene. These applications are very critical because the final pressure can reach 350 MPa and the evaluation of the performance of the machines is strongly connected to the proper operation and performance of the valve itself. The arrangement of cylinders requires generally a certain compactness of valve to withstand high fatigue stresses, but at the same time pressure drop and operating life are very important. In recent years the reliability of the machines has been improving over and over and the customers’ needs are very stringent. Therefore the use of poppet valves has been extended to other cases. In general the mentioned applications are heavy duty services and the simulation of the valves require some coefficients to be used in the differential equations, able to describe the movement of plate/disk or poppet and the flow and related pressure drop through the valves. Such coefficients are often determined in an experimental way in order to have a simulation closer to the real operating conditions. For the flow coefficients it is also possible today to use theoretical programs capable of determining the needed values in a quick and economical way. Some investigations have been carried out to determine the values for certain geometries of poppet valves. The results of the theory have been compared with some experimental tests. The good agreement between the various methods indicates the most suitable procedure to be applied in order to have reliable data. The advantage is evident as the time necessary for the theoretical procedure is faster and less expensive. This is of significant importance at the time of the design and also in case of a need to provide timely technical support for the operating behavior of the valves. Particularly for LDPE, the optimization of all the parameters is strongly necessary. The fatigue stresses of cylinder heads and valve bodies have to match in fact with gas passage turbulence and pressure drop, added to the mechanical behavior of the poppet valve components.

Experimental Research for Breakthrough Position of Horizontal Wells in Reservoirs with Bottom Water

2012 ◽  
Vol 524-527 ◽  
pp. 1232-1235 ◽  
Author(s):  
Li Feng Li ◽  
Xiang An Yue ◽  
Li Juan Zhang
Keyword(s):  
Pressure Drop ◽  
Bottom Water ◽  
Horizontal Wells ◽  
Concave Part ◽  
Entry Points ◽  
Heterogeneous Models ◽  
Two Factors ◽  
Well Trajectory ◽  
Trajectory Models ◽  
Swept Area

Finding the breakthrough position of horizontal wells is essential to water plugging and improving oil production in bottom water drive reservoirs. Physical modeling was carried out in this paper to research the law of bottom water’s movement. The experimental results indicated that: pressure drop in wells, well trajectory and area reservoir heterogeneity were all sensitive factors for breakthrough of bottom water, and the entry points of horizontal wells were determined by the combined function of them. In different well trajectory models, the concave down part of the well cooperate with pressure drop influenced the breakthrough position. Bottom water below the heel end reached the well earliest if the concave down part located at the heel end. When the concave part located at the middle of the well, the two factors played role respectively which resulted in breaking through of bottom water at two places with larger swept area. In different heterogeneous models, permeability difference and pressure drop were both favorable factors for bottom water’s non-uniformly rise. In the model that the heel end located at high permeability part, bottom water under the heel end reached the well earliest. If the heel end was set at the low permeability part, the breakthrough of bottom water occurred at the middle of the well.

Radar target identification using a combined early-time/late-time E-pulse technique

1998 ◽  
Vol 46 (9) ◽  
pp. 1272-1278 ◽  
Author(s):  
Q. Li ◽  
P. Ilavarasan ◽  
J.E. Ross ◽  
E.J. Rothwell ◽  
Kun-Mu Chen ◽  
...  
Keyword(s):  
Target Identification ◽  
Early Time ◽  
Radar Target ◽  
Late Time ◽  
Pulse Technique

The use and misuse of apparent resistivity in electromagnetic methods

Geophysics ◽  
1986 ◽  
Vol 51 (7) ◽  
pp. 1462-1471 ◽  
Author(s):  
Brian R. Spies ◽  
Dwight E. Eggers
Keyword(s):  
Apparent Resistivity ◽  
Early Time ◽  
Asymptotic Formulas ◽  
Voltage Response ◽  
Late Time ◽  
Induced Voltage ◽  
Resistivity Curve ◽  
Transient Electromagnetic ◽  
Electromagnetic Methods ◽  
Tem Method

Problems and misunderstandings arise with the concept of apparent resistivity when the analogy between an apparent resistivity computed from geophysical observations and the true resistivity structure of the subsurface is drawn too tightly. Several definitions of apparent resistivity are available for use in electromagnetic methods; however, those most commonly used do not always exhibit the best behavior. Many of the features of the apparent resistivity curve which have been interpreted as physically significant with one definition disappear when alternative definitions are used. It is misleading to compare the detection or resolution capabilities of different field systems or configurations solely on the basis of the apparent resistivity curve. For the in‐loop transient electromagnetic (TEM) method, apparent resistivity computed from the magnetic field response displays much better behavior than that computed from the induced voltage response. A comparison of “exact” and “asymptotic” formulas for the TEM method reveals that automated schemes for distinguishing early‐time and late‐time branches are at best tenuous, and those schemes are doomed to failure for a certain class of resistivity structures (e.g., the loop size is large compared to the layer thickness). For the magnetotelluric (MT) method, apparent resistivity curves defined from the real part of the impedance exhibit much better behavior than curves based on the conventional definition that uses the magnitude of the impedance. Results of using this new definition have characteristics similar to apparent resistivity obtained from time‐domain processing.

Formation-Rate-Analysis Technique: Combined Drawdown and Buildup Analysis for Wireline Formation Test Data

1999 ◽  
Vol 2 (03) ◽  
pp. 271-280 ◽  
Author(s):  
Ekrem Kasap ◽  
Kun Huang ◽  
Than Shwe ◽  
Dan Georgi
Keyword(s):  
Numerical Simulation ◽  
Steady State ◽  
Field Data ◽  
Formation Rate ◽  
Flow Analysis ◽  
Early Time ◽  
Late Time ◽  
Time Data ◽  
Analysis Techniques ◽  
Conventional Analysis

Summary The formation-rate-analysis (FRASM) technique is introduced. The technique is based on the calculated formation rate by correcting the piston rate with fluid compressibility. A geometric factor is used to account for irregular flow geometry caused by probe drawdown. The technique focuses on the flow from formation, is applicable to both drawdown and buildup data simultaneously, does not require long buildup periods, and can be implemented with a multilinear regression, from which near-wellbore permeability, p * and formation fluid compressibility are readily determined. The field data applications indicate that FRA is much less amenable to data quality because it utilizes the entire data set. Introduction A wireline formation test (WFT) is initiated when a probe from the tool is set against the formation. A measured volume of fluid is then withdrawn from the formation through the probe. The test continues with a buildup period until pressure in the tool reaches formation pressure. WFTs provide formation fluid samples and produce high-precision vertical pressure profiles, which, in turn, can be used to identify formation fluid types and locate fluid contacts. Wireline formation testing is much faster compared with the regular pressure transient testing. Total drawdown time for a formation test is just a few seconds and buildup times vary from less than a second (for permeability of hundreds of millidarcy) to half a minute (for permeability of less than 0.1 md), depending on system volume, drawdown rate, and formation permeability. Because WFT tested volume can be small (a few cubic centimeters), the details of reservoir heterogeneity on a fine scale are given with better spatial resolution than is possible with conventional pressure transient tests. Furthermore, WFTs may be preferable to laboratory core permeability measurements since WFTs are conducted at in-situ reservoir stress and temperature. Various conventional analysis techniques are used in the industry. Spherical-flow analysis utilizes early-time buildup data and usually gives permeability that is within an order of magnitude of the true permeability. For p* determination, cylindrical-flow analysis is preferred because it focuses on late-time buildup data. However, both the cylindrical- and spherical-flow analyses have their drawbacks. Early-time data in spherical-flow analysis results in erroneous p* estimation. Late-time data are obtained after long testing times, especially in low-permeability formations; however, long testing periods are not desirable because of potential tool "sticking" problems. Even after extended testing times, the cylindrical-flow period may not occur or may not be detectable on WFTs. When it does occur, permeability estimates derived from the cylindrical-flow period may be incorrect and their validity is difficult to judge. New concepts and analysis techniques, combined with 3-D numerical studies, have recently been reported in the literature.1–7 Three-dimensional numerical simulation studies1–6 have contributed to the diagnosis of WFT-related problems and the improved analysis of WFT data. The experimental studies7 showed that the geometric factor concept is valid for unsteady state probe pressure tests. This study presents the FRA technique8 that can be applied to the entire WFT where a plot for both drawdown and buildup periods renders straight lines with identical slopes. Numerical simulation studies were used to generate data to test both the conventional and the FRA techniques. The numerical simulation data are ideally suited for such studies because the correct answer is known (e.g., the input data). The new technique and the conventional analysis techniques are also applied to the field data and the results are compared. We first review the theory of conventional analysis techniques, then present the FRA technique for combined drawdown and buildup data. A discussion of the numerical results and the field data applications are followed by the conclusions. Analysis Techniques It has been industry practice to use three conventional techniques, i.e., pseudo-steady-state drawdown (PSSDD), spherical and cylindrical-flow analyses, to calculate permeability and p* Conventional Techniques Pseudo-Steady-State Drawdown (PSSDD). When drawdown data are analyzed, it is assumed that late in the drawdown period the pressure drop stabilizes and the system approaches to a pseudo-steady state when the formation flow rate is equal to the drawdown rate. PSSDD permeability is calculated from Darcy's equation with the stabilized (maximum) pressure drop and the flowrate resulting from the piston withdrawal:9–11 $$k {d}=1754.5\left({q\mu \over r {i}\Delta p {{\rm max}}}\right),\eqno ({\rm 1})$$where kd=PSSDD permeability, md. The other parameters are given in Nomenclature.

Investigation and Optimization of the Effects of Geologic Parameters on the Performance of Gravity-Stable Surfactant Floods

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 761-775 ◽  
Author(s):  
Shayan Tavassoli ◽  
Gary A. Pope ◽  
Kamy Sepehrnoori
Keyword(s):  
Salinity Gradient ◽  
Horizontal Wells ◽  
Sensitivity Study ◽  
Third Order ◽  
Fine Grid ◽  
Heterogeneous Reservoirs ◽  
Vertical Permeability ◽  
Well Spacing ◽  
Optimization Schemes ◽  
Very High

Summary A systematic simulation study of gravity-stable surfactant flooding was performed to understand the conditions under which it is practical and to optimize its performance. Different optimization schemes were introduced to minimize the effects of geologic parameters and to improve the performance and the economics of surfactant floods. The simulations were carried out by use of horizontal wells in heterogeneous reservoirs. The results show that one can perform gravity-stable surfactant floods at a reasonable velocity and with very-high sweep efficiencies for reservoirs with high vertical permeability. These simulations were carried out with a 3D fine grid and a third-order finite-difference method to accurately model fingering. A sensitivity study was conducted to investigate the effects of heterogeneity and well spacing. The simulations were performed with realistic surfactant properties on the basis of laboratory experiments. The critical velocity for a stable surfactant flood is a function of the microemulsion (ME) viscosity, and it turns out there is an optimum value that one can use to significantly increase the velocity and still be stable. One can optimize the salinity gradient to gradually change the ME viscosity. Another alternative is to inject a low-concentration polymer drive following the surfactant slug (without polymer). Polymer complicates the process and adds to its cost without a significant benefit in most gravity-stable surfactant floods, but an exception is when the reservoir is highly layered. The effect of an aquifer on gravity-stable surfactant floods was also investigated, and strategies were developed for minimizing its effect on the process.

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