Average Reservoir Pressure from a Horizontal Well Pressure Buildup Test

2005 ◽  
Author(s):  
Christine A. Ehlig-Economides ◽  
Kirby L. Wells
Keyword(s):  
Horizontal Well ◽  
Reservoir Pressure ◽  
Pressure Buildup

Evaluating the Performance of Horizontal Multi-Frac Wells in a Depleted Gas Condensate Reservoir in Sultanate of Oman

2022 ◽  
Author(s):  
Josef R. Shaoul ◽  
Jason Park ◽  
Andrew Boucher ◽  
Inna Tkachuk ◽  
Cornelis Veeken ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Gas Condensate ◽  
Integrated Analysis ◽  
Single Fracture ◽  
Reservoir Pressure ◽  
Well Test ◽  
Vertical Wells ◽  
Fracture Conductivity ◽  
Half Length

Abstract The Saih Rawl gas condensate field has been producing for 20 years from multiple fractured vertical wells covering a very thick gross interval with varying reservoir permeability. After many years of production, the remaining reserves are mainly in the lowest permeability upper units. A pilot program using horizontal multi-frac wells was started in 2015, and five wells were drilled, stimulated and tested over a four-year period. The number of stages per horizontal well ranged from 6 to 14, but in all cases production was much less than expected based on the number of stages and the production from offset vertical wells producing from the same reservoir units with a single fracture. The scope of this paper is to describe the work that was performed to understand the reason for the lower than expected performance of the horizontal wells, how to improve the performance, and the implementation of those ideas in two additional horizontal wells completed in 2020. The study workflow was to perform an integrated analysis of fracturing, production and well test data, in order to history match all available data with a consistent reservoir description (permeability and fracture properties). Fracturing data included diagnostic injections (breakdown, step-rate test and minifrac) and main fracture treatments, where net pressure matching was performed. After closure analysis (ACA) was not possible in most cases due to low reservoir pressure and absence of downhole gauges. Post-fracture well test and production matching was performed using 3D reservoir simulation models including local grid refinement to capture fracture dimensions and conductivity. Based on simulation results, the effective propped fracture half-length seen in the post-frac production was extremely small, on the order of tens of meters, in some of the wells. In other wells, the effective fracture half-length was consistent with the created propped half-length, but the fracture conductivity was extremely small (finite conductivity fracture). The problems with the propped fractures appear to be related to a combination of poor proppant pack cleanup, low proppant concentration and small proppant diameter, compounded by low reservoir pressure which has a negative impact on proppant regained permeability after fracturing with crosslinked gel. Key conclusions from this study are that 1) using the same fracture design in a horizontal well with transverse fractures will not give the same result as in a vertical well in the same reservoir, 2) the effect of depletion on proppant pack cleanup in high temperature tight gas reservoirs appears to be very strong, requiring an adjustment in fracture design and proppant selection to achieve reasonable fracture conductivity, and 3) achieving sufficient effective propped length and height is key to economic production.

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

A New Method for Estimating Average Reservoir Pressure: The Muskat Plot Revisited

2008 ◽  
Vol 11 (02) ◽  
pp. 298-306 ◽  
Author(s):  
James G. Crump ◽  
Robert H. Hite
Keyword(s):  
Direct Synthesis ◽  
New Method ◽  
Theoretical Ground ◽  
Time Behavior ◽  
Reservoir Pressure ◽  
Reservoir Properties ◽  
Pressure Derivative ◽  
Pressure Buildup ◽  
Heterogeneous Reservoirs ◽  
Fluid Properties

Summary This paper describes a new method for estimating average reservoir pressure from long-pressure-buildup data on the basis of the classical Muskat plot. Current methods for estimating average reservoir pressure require a priori information about the reservoir and assume homogeneous reservoir properties or use empirical extrapolation techniques. The new method applies to heterogeneous reservoirs and requires no information about reservoir or fluid properties. The idea of the method is to estimate from the pressure derivative the first few eigenvalues of the pressure-transient decay modes. These values are characteristic of the reservoir and fluid properties, but not of the pressure history or well location in the reservoir. The smallest eigenvalue is used to extrapolate the long-time behavior of the transient to estimate the final reservoir pressure. The second eigenvalue can be used to estimate the quality of the estimate. Numerical tests of the method show that it estimates average reservoir pressure accurately, even when the reservoir is heterogeneous or when partial-flow barriers are present. Examples with real data show that the behavior predicted by the theory is actually observed. We expect the method to have value in reservoir limits testing, in making consistent estimates of average reservoir pressure from permanent downhole gauges, and in characterizing complex reservoirs. Introduction Several different methods of interpreting pressure-buildup data to obtain average reservoir pressure have been proposed (Muskat 1937; Horner 1967; Miller et al. 1950; Matthews et al. 1954; Dietz 1965) in the past, and in recent years some new techniques have appeared in the literature (Mead 1981; Hasan and Kabir 1983; Kabir and Hasan 1996; Kuchuk 1999; Chacon et al. 2004). Larson (1963) revisited the Muskat method and put it on a firm theoretical ground for a homogeneous cylindrical reservoir. Some of the existing techniques depend on knowledge of the reservoir size and shape and assume homogeneous properties (Horner 1967; Miller et al. 1950; Matthews et al. 1954; Dietz 1965). Such methods may result in uncertain predictions when reservoir data are unavailable or reservoir heterogeneity exists. The inverse time plot by Kuchuk (1999) is essentially a modification of Horner's method (1967) and works well in reservoirs that can be treated as infinite during the time of the test. The hyperbola method proposed by Mead (1981) and further developed by Hasan and Kabir (1983) is an empirical technique, not based on fundamental fluid flow principles for bounded reservoirs (Kabir and Hasan 1996). Chacon et al. (2004) develop the direct synthesis technique, in which conventional theory is used to derive an average pressure directly from standard log-log plots. Homogeneous properties and radial symmetry are assumed. Muskat's original derivation was a wellbore storage model. Larson reinterpreted Muskat's method and derived relationships showing how Muskat's plot could be used to estimate average reservoir pressure in a cylindrical, homogeneous reservoir. This paper revisits the ideas underlying Larson's paper. Similar ideas are shown to hold for heterogeneous reservoirs of any shape. A new analysis technique replacing the Muskat plot by a plot of the pressure derivative simplifies the determination of average reservoir pressure. It is shown that parameters from analysis of a long buildup on a reservoir can be used in subsequent buildup tests to shorten the required time of the subsequent buildups. Finally, estimates for time required for a buildup in homogeneous reservoirs of any shape are given.

Determination of Average Reservoir Pressure from Pressure Buildup Tests

1972 ◽  
Author(s):  
Hossein Kazemi
Keyword(s):  
Reservoir Pressure ◽  
Well Test ◽  
Well Test Analysis ◽  
Test Analysis ◽  
Gas Well ◽  
Pressure Buildup ◽  
Production History ◽  
Calculated Average

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 analysis irrespective of gas composition, in reservoirs with pressure-dependent permeability and porosity, and in oil reservoirs where substantial gas saturation has been developed. Long-term production history need not be known. Introduction For analyzing pressure buildup data with constant flowrate before shut in, two plotting procedures are mostly used: The Miller-Dyes-Hutchinson (MDH) plot (1,8) and the Horner plot (2,8). The Miller-Dyes-Hutchinson plot is a plot of pws vs log Δt. The Horner plot consists of plotting the bottom hole shut-in pressure, pws vs log [(tp + Δt)/Δt]. Δt is the shut-in time and tp is a pseudo-production time equal to the ratio of total produced fluid and the last stabilized flowrate prior to shut in. This method was first used by Theis (3) in the water industry.

Pressure Buildup for Wells Produced at a Constant Pressure

1981 ◽  
Vol 21 (01) ◽  
pp. 105-114 ◽  
Author(s):  
C.A. Ehlig-Economides ◽  
H.J. Ramey
Keyword(s):  
Constant Pressure ◽  
Variable Rate ◽  
Reservoir Pressure ◽  
Well Test ◽  
Well Test Analysis ◽  
Pressure Flow ◽  
Value Analysis ◽  
Pressure Buildup ◽  
Constant Flow Rate ◽  
Constant Rate

Abstract Conventional well test analysis has been developed primarily for production at a constant flow rate. However, there are several common reservoir production conditions which result in flow at a constant pressure instead of a constant rate. In the field, wells are produced at constant pressure when fluids flow into a constant-pressure separator and during the rate decline period of reservoir depletion. In geothermal reservoirs, produced fluids may drive a backpressured turbine. Open wells, including artesian water wells, flow at constant atmospheric pressure.Most of the existing methods for pressure buildup analysis of wells with a constant-pressure flow history are empirical. Few are based on sound theory. Hence, there is a need for a thorough treatment of pressure buildup behavior following constant-pressure production.In this work, the method of superposition of continuously changing rates was used to generate an exact solution for pressure buildup following constant-pressure flow. The method is general. Storage and skin effects were incorporated into the theory, and both bounded and unbounded reservoirs were considered. Buildup solutions were graphed using conventional techniques for analysis. Horner's method for plotting buildup data after a variable-rate flow was found to be accurate in a majority of cases. Also, the method by Matthews et al. for determining the average reservoir pressure in a closed system was determined to be correct for buildup following constant-pressure flow. Introduction When a flowing well is shut in, the pressure in the wellbore increases with time as the pressures throughout the reservoir approach a static value. Analysis of the pressure increase, or pressure buildup, often provides useful information about the reservoir and the wellbore itself. Techniques exist for determination of wellbore storage, skin effect, reservoir permeability and porosity, and either the initial reservoir pressure or the volumetric average reservoir pressure at the time the well was shut in. Effects of fractures penetrated by or near the wellbore also can be detected, as well as nearby faults or reservoir drainage boundaries.Most of the techniques for pressure buildup analysis were developed for wells which, prior to shut-in, were produced at a constant rate. When the production rate before shut-in changes rapidly, conventional analysis is often suspect. If the exact rate history is known, the theory of superposition in time of constant-rate solution leads to the method derived by Horner which compensates for changing production rates. This method results in long calculations. However, in the same paper Horner proposed a simplified procedure in which the last established rate was assumed constant and the flow time was set equal to the cumulative production divided by the last established rate. Other methods for analysis of pressure buildup after a variable-rate production history were proposed by Odeh et al.A special case of variable-rate production results when a well is produced at constant pressure. The first published application of pressure buildup analysis for a well produced at constant pressure prior to shut-in was by Jacob and Lohman. Their graph of residual drawdown vs. total time divided by shut-in time results in a semilog straight line. SPEJ P. 105^

Pressure Buildup Equations for Spherical Flow Regime Problems

1974 ◽  
Vol 14 (06) ◽  
pp. 545-555 ◽  
Author(s):  
W.E. Culham
Keyword(s):  
Flow Regime ◽  
Transition Period ◽  
Oil Wells ◽  
Reservoir Pressure ◽  
Pressure Data ◽  
Pressure Buildup ◽  
Practical Utility ◽  
Straight Line ◽  
Practical Guidelines ◽  
Buildup Curve

Abstract Pressure buildup and flow tests conducted in wells that do not completely penetrate the producing formation or that produce from only a small portion of the total productive interval can generate noncylindrical flow regimes and require special interpretation procedures. Frequently a spherical flow regime is representative, and a new equation based on the continuous point-source solution to the diffusivity equation in spherical coordinates is presented for analyzing tests of this nature. The practical utility of the equation is demonstrated by practical utility of the equation is demonstrated by analyzing tests involving restricted producing intervals that cannot be treated with existing analytic methods.Practical guidelines for applying the proposed equation are developed by analyzing pressure data generated by a numerical simulator and more complex analytic solutions for variety of special completion situations. Equations for determining static reservoir pressure, formation permeability, and skin factors pressure, formation permeability, and skin factors are derived and their validity verified under theoretical test conditions. The equations presented should have a variety of applications, but are particularly suited for analyzing pressure data from particularly suited for analyzing pressure data from drillstem tests with short flow periods. Introduction The fundamental equation for analyzing pressure buildup tests of oil wells was presented by Horner in 1951. This equation is based on the "line source" solution to the boundary value problem describing the pressure distribution resulting from the cylindrical flow of a slightly compressible fluid in an infinite reservoir. To achieve cylindrical flow the wellbore of a well must completely penetrate the producing formation. Although this restriction is often satisfied, in many tests it is not; for example, oil wells producing through perforated casing may have only a small portion of the total production interval perforated, or in the case of production interval perforated, or in the case of drillstem tests only a small interval (often 10 to 15 ft) of a thick (hundreds of feet) homogeneous formation may be selected for testing. Tests involving restricted producing intervals of this type have a characteristic buildup curve as described by Nisle and by Brons. These authors demonstrated that Horner's conventional equation could also be used for restricted producing interval problems, provided the correct portion of the buildup problems, provided the correct portion of the buildup curve is used. They showed that during a short period after starting production (or equivalently period after starting production (or equivalently after shut-in) the well behaves as if the total sand thickness were equal to the interval open to flow. That is, Horner's equations apply if the total sand thickness, h, is replaced by the producing interval thickness, h. They also showed that after a transition period the late part of the buildup curve could be used in the conventional manner to calculate formation permeability and static reservoir pressure. Kazemi and Seth extended the work of pressure. Kazemi and Seth extended the work of Nisle by including the effect of anisotropy; they also presented an equation, based on an analytic solution developed by Hantush, for estimating the shut-in time required for the development of the second straight-line portion in a conventional plot --i.e., p vs In (t + Deltat/Deltat. The first straight-line part o the buildup curve usually lasts only a few part o the buildup curve usually lasts only a few minutes and may often be obscured by afterflow, whereas the latter straight-line portion may take several hours to develop and may not even occur for practical shut-in times if the formation is thick and the producing time is relatively short. This paper demonstrates that the transition period paper demonstrates that the transition period between the two cylindrical flow periods can be analyzed with the spherical* flow equations presented here. In addition, practical guidelines presented here. In addition, practical guidelines cue developed for their application.Moran and Finklea first suggested that a pressure buildup equation based on spherical now pressure buildup equation based on spherical now was necessary to correctly analyze pressure data obtained from wireline formation testers. In many respects this study is similar; in fact, the basic pressure buildup equation (although it was derived pressure buildup equation (although it was derived from a different starting equation) presented here was used by Moran and Finklea in analyzing wireline formation test data. SPEJ P. 545

scholarly journals Inflow Performance Analysis of a Horizontal Well Coupling Stress Sensitivity and Reservoir Pressure Change in a Fractured-Porous Reservoir

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Mingxian Wang ◽  
Zifei Fan ◽  
Wenqi Zhao ◽  
Ruiqing Ming ◽  
Lun Zhao ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Horizontal Wells ◽  
Pressure Change ◽  
Sensitivity Coefficient ◽  
Stress Sensitivity ◽  
Reservoir Pressure ◽  
Well Productivity ◽  
Damage Rate ◽  
Porous Reservoir ◽  
Inflow Performance

Abstract Stress sensitivity has always been a research hotspot in fractured-porous reservoirs and shows huge impacts on well productivity during the depletion development. Due to the continuous reservoir pressure change, accurate evaluation of stress sensitivity and its influence on well productivity is of great significance to optimize well working system. Taking horizontal well trajectory as the research object, the principal focus of this work is on the analysis of inflow performance for a horizontal well coupling stress sensitivity and reservoir pressure change in a fractured-porous reservoir. Firstly, a relationship between permeability damage rate and stress sensitivity coefficient was established to quantitatively evaluate the influence of reservoir pressure and stress sensitivity on reservoir permeability. Secondly, considering stress sensitivity and reservoir pressure drop, a set of practical productivity equations were derived for a horizontal well in a fractured-porous reservoir by adopting the equivalent seepage resistance method. Finally, the influence of relevant important factors on the inflow performance of horizontal wells was discussed in depth. Results show that a positive correlation exists between stress sensitivity coefficient and maximum permeability damage rate. At the same maximum permeability damage rate, high initial reservoir pressure corresponds to low stress sensitivity coefficient. In general, stress sensitivity coefficient mainly ranges from 0 to 0.2. Reservoir pressure change drastically affects the production dynamic characteristics of horizontal wells, and both the inflow performance curve and the production index curve decline and shrink as reservoir pressure decreases. Stress sensitivity is negatively correlated with horizontal well productivity, and the inflow performance/production index curve bends closer to bottom-hole pressure axis, and an inflection point can be observed with the aggravation of stress sensitivity. In addition, horizontal wellbore length and initial reservoir permeability also show significant effects on the inflow performance and are positively correlated with well productivity. For water cut, it has little effect on the well production when bottom-hole pressure drawdown is low, but its effect gets stronger as the drawdown becomes higher. Meaningfully, depending on these newly established productivity equations, a reasonable production system can be quantitatively optimized and achieved for the horizontal wells in fractured-porous reservoirs.

Hydraulic Fracturing to Successfully Exploit Depleted Gas Reserves: A Case History from the North Sea

2022 ◽  
Author(s):  
Mark Norris ◽  
Marc Langford ◽  
Charlotte Giraud ◽  
Reginald Stanley ◽  
Steve Ball
Keyword(s):  
Hydraulic Fracturing ◽  
North Sea ◽  
Case History ◽  
Gas Flow ◽  
Horizontal Well ◽  
Hydraulic Fractures ◽  
Reservoir Pressure ◽  
Well Test ◽  
Short Period ◽  
Gas Fields

Abstract Hydraulic fracturing has been well established in the Southern North Sea (SNS) since the mid-1980s; however, it has typically been conducted as the final phase of development in new gas fields. One of these fields is Chiswick located in the Greater Markham area 90 miles offshore UK in 130 ft of water. Following an unsuccessful well repair of the multi-fractured horizontal well C4, it was decided to cost-effectively and expediently exploit the remaining pressure-depleted reserves near the toe via a single large fracture initiated from a deviated sidetrack wellbore designated C6. A deviated wellbore was chosen versus the original near-horizontal well to reduce well risk and costs and ultimately deliver an economic well. Several key challenges were identified, and mitigating measures were put in place. Modular formation dynamics tester data from the sidetrack open hole indicated the reservoir pressure gradient had depleted to 0.23 to 0.25 psi/ft, raising concerns about the ability of the well to unload the fluid volumes associated with a large fracture treatment. Wellbore deviation and azimuth with the associated potential for near-wellbore tortuosity would drive a typically short perforation interval (i.e., 3 ft). However, a compromise to mitigate convergent pressure loss in depletion was required, and the perforation interval was therefore set at 14 ft with provision made for robust step-down tests (SDT) and multi-mesh sand slugs. To further offset any near-well convergence pressure drop during cleanup, an aggressive tip screenout (TSO) proppant schedule, including a high concentration tail-in (12 PPA) with an aggressive breaker schedule, was executed to fully develop propped hydraulic width. Following formation breakdown and SDT to 40 bbl/min, the well went on near-instantaneous vacuum. Clearly, an extremely conductive feature had been created or contacted. However, upon use of a robust crosslinked gel formulation and 100-mesh sand, the bottomhole and positive surface pressure data allowed a suitable fracture design to be refined and placed with a large width, as evidenced by the extreme 2,309-psi net pressure development over that of the pad stage while placing 500,500 lbm of 16/30 resin-coated (RC) intermediate strength proppant (ISP) to 12 PPA. Although a lengthy nitrogen lift by coiled tubing (CT) was planned, the well cleanup response in fact allowed unaided hydrocarbon gas flow to surface within a short period. The well was then further beaned-up under well test conditions to a flow rate of approximately 26 MMscf/D under critical flowing conditions with a higher bottomhole flowing pressure than that of the original C4 well. Given the last producing rate of the original multiple fractured horizontal wellbore was 27 MMscf/D at a drawdown of 1,050 psi through two separate hydraulic fractures, then the outcome of this well was judged to be highly successful and at the limit of predrill expectations. This case history explains and details the rationale, methods, and techniques employed in well C6 to address the challenge of successful hydraulic fracture stimulation in a depleted formation. Challenges were addressed by combining a number of techniques, coupled with field experience, resulting in a highly productive well despite the relatively low reservoir pressure coupled with a limited time frame to plan and execute. These techniques are transferrable to other offshore gas fields in the region where reservoir depletion makes economic recovery difficult or indeed prohibitive.

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