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Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 13–17, 1999

Paper Number: PETSOC-99-53

... reservoir performance assumption directional drilling bottom hole pressure wellbore annulus pressure annular pressure drilling drillstem/well testing permeability

**drillstem****testing**information influx rate drilling operation kpa drilling bha reservoir pressure mathematical model horizontal...
Abstract

Abstract This paper presents the case studies of the reservoir performance while under-balanced drilling. The increase of the length of the well bore provides a unique transient effect that, with an appropriate mathematical model, some reservoir parameters can be obtained. The mathematical model used for this study is the discrete flux element method1. Applying this mathematical model, Fracmaster Ltd. analyzed the bottom hole pressure data from two coiled tubing under-balanced drilling jobs. Unlike the well testing of well bores with constant well length, for this method, due to the complex transient effect of draw down and increase of the physical length of the well, the calculated reservoir parameters are almost unique. Due to the increase of the wellbore length, there is almost a continuous pulse reaching the upper and lower boundaries. Thus the solution is very sensitive to the reservoir thickness. Introduction Underbalanced drilling is a growing technology that has certain advantages compared to overbalanced drilling. In underbalanced drilling, the wellbore pressure inside the annulus is to be kept less than that of the reservoir pressure. This allows reservoir influx into the wellbore while drilling to prevent the invasion of the drill cuttings into the reservoir matrix. To obtain the underbalanced condition one has to lighten the weight of the fluid inside the annulus to decrease the hydrostatic pressure. The usual method is by injection of a neutral gas such as nitrogen through tubing. The amount of the reservoir influx is a function of the underbalanced degree (pressure drop at the formation) as well as the well bore length (as the drilling proceeds the length of the well bore increases). The increase in the producing length provides a unique transient effect that can be used to analyze the reservoir performance and to estimate some reservoir parameters such as reservoir thickness, permeability, and the trend of the increase or decrease of the productivity along the wellbore. In well testing of horizontal wells with constant length, the effect of the reservoir thickness may be observed at short times but most of the time it is masked by the wellbore storage. However, in underbalanced drilling, increase in the wellbore length creates a continuous disturbance in the drainage zone. These disturbances, in the form of pulses, hit the upper and lower boundaries. Therefore, the solution and the reservoir performance are very sensitive to the reservoir height and the reservoir diffusivity. For well testing of horizontal wells with constant length, using several different sets of the parameters, one can satisfy the reservoir performance. For underbalanced drilling there is one unique set of the parameters. Several factors affect the influx rate. The most important factors are rate of penetration (ROP), or drilling velocity, pressure drop at the wellbore while drilling or amount of under-balance, wiper trip periods, shut-ins and flow tests. The influx rate at any time is a function of the drilling activity history. The improvement or deterioration of the reservoir quality (productivity) along the wellbore could not be inferred from the influx rate at a given time without consideration of the complete drilling history.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 13–17, 1999

Paper Number: PETSOC-99-29

..., including gaswell testing, workover and completions, surface casing vent tests, and nitrogen cushion drill stem tests. Introduction Closed chamber testing techniques for

**drillstem****tests**were first developed and described 1–4 in the early seventies and eighties. These same techniques were extended to...
Abstract

Abstract New rapid methods for testing oilwells are presented based on modified closed chamber theory. The tests are of great assistance in solving pumping problems. In the case of a sudden drop in production the tests define the problem in real time. Tubing leaks, pump failure, defective check valve, or flowline failure can readily be detected at the time of the test and remedied in a cost effective manner The tests are of short duration (twenty minutes or less). They have minimum equipment requirements (a critical flow prover, a high- resolution pressure recorder, and a laptop computer). Several tests can be conducted in a single day, travel time included. The mass balance theory and relevant equations behind these tests are developed and explained with emphasis on the practical aspects. Test procedures are described with step by step detail in field examples. One of these examples obviated the need for a previously ordered service rig. Another example shows how a simple non-quantitative visual scan of the pressure response can be used to immediately recognize problems. (In this case the problem was a severe foam buildup). Some other applications of the method are mentioned, including gaswell testing, workover and completions, surface casing vent tests, and nitrogen cushion drill stem tests. Introduction Closed chamber testing techniques for drillstem tests were first developed and described 1–4 in the early seventies and eighties. These same techniques were extended to include pumping well analysis, first published in 1980 5 and other later papers 6–10 As the name suggests, all flow rate measurements were measured under closed chamber conditions. That is the surface valve was closed when measuring inflow rates during a drillstem test. Similarly the casing was closed while measuring inflow rates for pumping wells. The technique has now been modified to enable measurements of inflow rates in any non closed chamber situation: i.e. whenever the surface valve is open. The method of testing described uses the same mass balance equations developed for closed chamber testing, but extends their application. The extensions remove the assumption that the flowrate is constant when the prover is being vented. They also provide the ability to calculate reservoir inflow rates at the same time the well is flowing at surface. APPLICATION AND DEFINITIONS Some applications for this new technique are: Pumping oil well: Venting the annulus of a pumping well to evaluate the wellbore gas volume, the annular gas rate and the inflow rate of gas and oil when the pump is deactivated. Gas well testing: Determining sandface gas influx rates as a gas well is being produced at surface. Present practice is to report the surface flow rate as though it were equivalent to the downhole sandface rate. This is seldom true. For this reason reservoir computations utilizing rate data are frequently incorrect. This problem is overcome with the new testing technique which calculates adjusted sandface rates directly.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 13–17, 1999

Paper Number: PETSOC-99-30

... rate was increased from test 1 to test 3. The injection rates of three tests are presented in Figure 1. The bottom hole pressures monitored during the well testing are shown in Figure 3. injection rate

**drillstem****testing**oil sand reservoir reservoir geomechanics pressure response void ratio...
Abstract

Abstract Pressure transient testing techniques such as pressure buildup, pressure drawdown, and constant rate injection have been used in petroleum industry for well performance evaluation and reservoir characterization. Conventional method of analysis usually assumes that permeability and compressibility of the reservoir formation are constant or a function of pore pressure. This assumption has limitations when applied to an oil sands reservoir because of the unconsolidated deformable nature of oil sands. Three injection tests were conducted in an oil sands reservoir at a depth of about 500 m. History matching of the field injection data using a fully coupled reservoir-geomechanical simulator demonstrates that the permeability and compressibility of oil sands are interrelated and effective stress dependent. Introduction The basic principle of pressure transient testing techniques, which are prevalent in petroleum industry, is to create and observe changing wellbore pressures. Appropriate and comprehensive interpretation of recorded well testing data provides information into reservoir properties such as permeability and compressibility. Conventional analysis is based on the principle of mass conservation, assuming that the permeability, porosity and compressibility of fluid are dependent on the pore pressure only. This simplified assumption has limitations when applied to an oil sands reservoir because oil sands will deform subjected to fluid injection and withdrawal, thereby causing changes in pore pressure and total stresses. Therefore, in order to interpret the well testing data in oil sands reservoir, coupled diffusion-deformation analysis, which considers the principle of mass conservation and equilibrium, should be used.1,2,3 In this paper, a history matching of the pore pressure responses of three injection tests in an oil sands reservoir was carried out using a fully coupled reservoir-geomechanical simulator. This exercise provides some estimate on the flow (permeability) and deformation response of oil sands subjected to water injection. INJECTION TESTS Three injection tests were conducted in a cased well at Burnt Lake, Alberta. The well was completed with a diameter of 178 mm. The perforation zone is 5 m in the middle of the oil sands layer, which is 21 m thick, and has an overburden of 505 m. The overlying and underlying formations of the oil sands layer can be considered impermeable because it is capped and underlain by shale layers of 3 to 5 m. The oil sands layer has an initial pore pressure of 3.3 MPa and its in situ porosity is 33%. The void ratio of oil sands layer is 0.4893, which is the ratio of the volume of void to the volume of solid. In each test, cold water was injected into the oil sands formation through the tubing at a controlled rate for some interval, and then the well was shut in allowing the bottom hole pressure to decay to its initial in situ state. The bottom hole pressure was monitored during the injection and shut-in periods. The injection rate was increased from test 1 to test 3. The injection rates of three tests are presented in Figure 1. The bottom hole pressures monitored during the well testing are shown in Figure 3.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 13–17, 1999

Paper Number: PETSOC-99-63

... pressure counterweight

**drillstem****testing**dynamometer data pump fillage ABSTRACT A procedure is described that allows an operator to identify artificial lift wells which are operating inefficiently. A logical sequence of steps is presented for acquiring performance data such as casing annulus fluid...
Abstract

Abstract A procedure is described that allows an operator to identify artificial lift wells which are operating inefficiently. A logical sequence of steps is presented for acquiring performance data such as casing annulus fluid level, casing pressure, bottomhole pressure, dynamometer analysis and motor power/current. The criteria to be used in determining the system efficiency and the causes of inefficiency are presented. Following the logical methodology will reduce the time and effort required to perform a well analysis and will result in a complete understanding of the well's performance. Understanding a well's performance is necessary before an operator can modify an artificial lift system and improve performance efficiently. A field case on a well in which the electricity cost was reduced by one-half and the mechanical maintenance cost was reduced by twothirds is presented. Introduction During depressed oil price markets, the need to increase oil production, reduce operating costs and increase net income requires an integrated analysis of the pumping system. The analysis should include the performance and interaction of all the elements: the reservoir, the wellbore, the gas separator, the downhole pump, the rod string and pumping unit in beam pumped wells and the prime mover. Such system analysis can be undertaken efficiently using portable notebook computer based data acquisition systems in conjunction with appropriate transducers and software 1 . Field experience undertaking such analysis in many wells has resulted in the development of a procedure which insures that a good understanding of an artificial lift system is obtained with a minimum of cost and effort. The object of this paper is to present this methodology to improve artificial lift operations. The end result of such system analysis should be the complete understanding of the performance of a given well so that changes to reduce operating costs and increase production can be implemented. In general the following steps should be undertaken: Analyze the well's inflow performance to insure that the maximum production is obtained. Analyze each well's overall electrical efficiency to identify wells needing improvement. Analyze the performance of downhole pump and downhole gas separator. Analyze the mechanical loading of rods, gearbox and beam in beam pump systems. Analyze the performance of the prime mover. Portable notebook computers, state of the art sigma-delta Modulation 15 analog to digital converters and modern sensors allow the acquisition of pressure, load, acoustic signals, acceleration, motor power, motor current and other data with greater accuracy than previously possible. Modern sigma-delta analog to digital converters have a resolution better than one part in a million at data acquisition rates commonly used in oil field analysis. Modern Windows software (with help files) simplifies the acquisition and the analysis of well performance. METHODOLOGY The steps to be followed in defining the performance of a system should result in the maximum of information with a minimum of time and effort. Having access to information about the well's characteristics, electrical and mechanical equipment, completion data and well tests in a computerstored database facilitate time efficient analysis.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–9, 1998

Paper Number: PETSOC-98-53

... characterization mpa waterflooding water management hydraulic fracturing effective stress radial distance flow in porous media permeability base case injection injection pressure

**drillstem****testing**total stress change displacement wellbore stress change drillstem/well testing vertical total stress...
Abstract

Abstract Injection of water into reservoirs are very common in petroleum industry. For examples, produced water is disposed into deep, permeable reservoirs. In water flooding recovery process, water of huge volume is injected into reservoir to displace oil-in-place to nearby producers. In thermal recovery methods, steam is injected into heavy oil or oil sand reservoirs to reduce the viscosity of oil to enhance the recovery rate. In-situ stress determination or hydraulic fracturing tests involve injection of small volume water at high rate into reservoir. In some of these injection activities, hydraulic fracturing may not be desirable. Thus, an estimation of the fracturing pressure is very important. In conventional practice, the injection pressure for fracturing is assumed to be equal to the minor principal total in-situ stress. However, injection of water into formation causes expansion of formation matrix, and thus changes in total in-situ stresses. The magnitude of the total stress change is a function of injected water volume, rate of injection, formation deformability and permeability. Sometimes, water injection may cause a rotation in principal stresses resulting in a change in the orientation of fracturing. This paper presents a case study of water injection test in a disposal well, along its analysis. Parametric studies using a fully coupled fluid flow and deformation simulator are conducted to investigate the effects of reservoir permeability and deformability on the injection pressure for hydraulic fracturing initiation. Introduction Hydraulic fracturing in formation near a wellbore is assumed to occur when the minimum principal effective stress becomes zero given that the tensile strength of the formation is small 1 . The definition of effective stress is given as: Equation (1) (Available in full paper) where σ is the total stress, and p is the pore pressure. The sign convention here is negative for tension and positive for compression. The pore pressure is always positive. In field practice, the injection pressure (or pore pressure) at bottom hole is estimated from the measured wellhead pressure. The total stress σ is assumed to remain unchanged during injection. Thus, from equation (1) the injection pressure for fracturing is equal to the initial minor principal total in-situ stress. However, due to water injection into the reservoir formation, the formation matrix expands, which causes changes in σ. The pore pressure could be higher than the initial total stress without causing hydraulic fracturing if σ increases due to water injection 2 . The objectives of this study are: to determine the maximum injection pressure without causing any hydraulic fracturing in a given reservoir, and< to evaluate the effects of reservoir permeability and deformability on the injection pressure and total stress changes. These objectives were achieved by (i) history-matching the transient pressure response observed from a water injection test in a disposal well, (ii) analysis of a base case using the reservoir properties estimated from the history matching, and (iii) conducting parametric studies to investigate the effects of reservoir properties on the well injectivity.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–9, 1998

Paper Number: PETSOC-98-20

..., i.e. infinite reservoir, second case is box-shape bounded, i.e. rectangular reservoir, its length is "a" and width is "b". flow regime drillstem/well testing wellbore storage coefficient algorithm dimensionless pressure drop horizontal well upstream oil & gas

**drillstem****testing**...
Abstract

Abstract This paper set up a mathematical model of three-dimensional transient flow to describe the pressure behavior for horizontal well with wellbore storage and skin effect in naturally fractured infinite and box-shape-bounded reservoirs. On the basis of obtaining solutions of mathematical model, we study practical algorithms of the pressure response, and use methods of numerical integrating and numerical inversion of Laplace transforms to compute typical curves for recognizing flow regimes and ape curve well test analysis. Based on these, this paper further gives expression equation of dimension pressure in all flow regimes for horizontal well percolation, and analyzes mainly effect factor of the occurrence of the flow regimes. At the same time, this paper presents analysis methods of conventional well test and procedures of type curve analysis. These methods are used to interpret practical well testing data of a example horizontal well in Xinjiang of P.R. China, defined by Warren and Root 10 . The interporosity flow is modeled with the pseudo-steady state flow equation. The external boundary are both infinite and box-shape bounded reservoirs. Applying the superposition theorem includes fracture permeability, skin factor, wellbore storage coefficient. Storativity ratio, interporosity flow coefficients are obtained. Analysis methods of well test presented in this paper are reliable and applicable. Introduction Many papers 1–6 had published for well test analysis methods of homogenous reservoirs. Recently several years, well test analysis methods of horizontal well in dual-porosity reservoirs had been reported. R. de S. Carvalho et al 7 presented well test analysis method of dual-porosity infinite reservoir, R. Aguilera et al 8 presented analytical solution for pressure drawdown and buildup analysis of horizontal well in anisotropic reservoirs with natural fractures, but wellbore storage was not considered. Kui-Fu Du et al 9 presented transient pressure response of horizontal well in layered and naturally fractured reservoirs with dual-porosity behavior. In this paper, we consider the dual-porosity model as Wellbore storage and skin effects. On the basis of obtaining solution of mathematical model, we present practical algorithms of the pressure response, and used methods of numerical integration and H. Stefest 11 algorithm to compute pressure derivative typical curves for recognizing flow regimes and type curve for well test analysis. Methods presented in this paper are used to interpret well testing data of a example horizontal well in Xinjiang of P. R. China, we obtained fracture permeability, skin factor, wellbore storage coefficient, Storativity ratio, interporosity flow coefficient. Physical Model We applies the dual-porosity model introduced by Warren and Root 10 . Fig.1 shows a schematic picture of horizontal well. To set up mathematical model of horizontal well transient flow, we establish the following additional hypotheses: The reservoir is horizontal with constant fracture and matrix permeability (k f and k m ). It has uniform thickness(h), constant fracture and matrix porosity (• f and • m ), the initial pressure is equal to constant (P i ). The external boundary of reservoir is divided two cases, first case is infinite lateral extension, i.e. infinite reservoir, second case is box-shape bounded, i.e. rectangular reservoir, its length is "a" and width is "b".

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–9, 1998

Paper Number: PETSOC-98-49

... periods. case fracture permeability fracture permeability upstream oil & gas buildup ten-layer model permeability wellbore storage crossflow partial penetration effect saturation drawdown flow period reservoir shutin fractured reservoir

**drillstem****testing**conclusion fracture...
Abstract

Abstract Permeabilities from layer to layer can vary significantly in naturally fractured reservoirs. This study makes a comparison of geometric mean fracture permeability with permeabilities from well testing data in a layered naturally fractured reservoir. The research was conducted with a model that contains 10 layers that are naturally fractured. The 10-layer model is validated by comparing its drawdown and buildup behavior against the behavior of a single-layer model. It is shown that permeability of the 10-layered reservoir calculated using a single-layer method will be much larger than the geometric mean and even the arithmetic mean, and will reflect the 2 layers with the largest permeabilities. If this is used in reservoir studies, it can lead to very optimistic forecasts. The problem of multi-layered permeability behavior may be recognized during a drawdown by a pressure derivative indicating partial completion effects even if the well is perforated in all fractured layers. During a buildup this recognition is more difficult because the shape of the buildup curve is affected by the length of the flow period previous to shutin. Introduction Outcrop information, imaging logs and production logs, have shown that in some cases naturally fractured reservoirs are composed by many layers 1 . The thinner the layer the smaller the fracture spacing (or distance between natural fractures). Under these circumstances some of the fractures might be intersected by the wellbore and some might not as shown on Figure 1 . A production log would show only the fluid entrance points into the wellbore. It is important to emphasize that the production log would not give an indication of net pay in the naturally fractured reservoir, only an indication of where the wellbore intersects the most important fractures. It is not unusual to see from a production log that out of 100 ft perforated in a fractured reservoir only 5 to 10 ft contribute production into the wellbore even if the 100 ft are true net pay. This is the result of a typical situation in most naturally fractured reservoirs I am familiar with, i.e., that the matrix has a very low permeability which does not permit efficient fluid flow into the wellbore. The same tight matrix, however, can flow very efficiently into the natural fractures 1 . One of the first papers dealing with pressure behavior of layered reservoirs was published by Leftkovits et al 2 . There was no communication between layers except at the wellbore. Later Russell and Prats 3 studied the practical aspects of interlayer cross flow, and concluded that the early time response would be similar to the response of a well draining a layered reservoir with no cross flow. Prijambodo et al 4 studied the early time performance of a well in a reservoir with cross flow and concluded that the pressure behavior was remarkably different from that of an equivalent single layer system. They indicated that the early time response could be divided in flow periods.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–9, 1998

Paper Number: PETSOC-98-21

... convenience, we use results in dimensionless form. Dimensionless pressure and dimensionless time are defined as: upstream oil & gas infinite pressure distribution pressure response acting drillstem/well testing double porosity reservoir test-analysis problem

**drillstem****testing**point source...
Abstract

Abstract A mathematical model is presented to evaluate pressure response of a horizontal well in bounded homogeneous and naturals fractured reservoirs. The model also used to understand the pressure behavior of a horizontal well in an infinite acting, one, two or three sealing faults and closed rectangular Furthermore we introduce skin and wellbore storage in the numerical solution. Use of the technique is illustrated with the case of a horizontal well in a naturally fractured reservoir. Introduction As a horizontal well technology is becoming more suitable in developing naturally fractured reservoirs, tight reservoirs, heavy oil reservoirs and fine reservoirs. The pressure transient of horizontal well has become a very interesting topic. Many papers on well testing have been presented since Ramey's 1 and Gringarten's 2 review in 1982 and 1984, The earlier articles are about reservoir performance and productivity of horizontal well. 4,5 In recent years, the paper deals with pressure distribution of horizontal well for homogenous and naturally fractured reservoirs 6–8 . Most recently, a number of papers have cared for the interpretation of horizontal well test data and horizontal well-layered reservoir and multi-lateral well. 3,13,14 Unlike vertical wells, reservoirs have to be seen as three-dimensional formations. Hence, the pressure behavior of a horizontal well is more sophisticated than that of a vertical well. Transient behavior is an important factor in understanding the horizontal well performance. Although Mathematical modeling of horizontal wells is abundant in the literature, seldom papers pay attention to boundaries including rectangular, channel, parallel, one fault and computational method. Only recently several papers appear to discuss boundaries case 3,10,11,13 , R. Aguilera and M.C. Ng 3 using the method of images, handle wellbore storage and skin in pressure drawdowns and buildup of vertical well in bounded rectangular naturally fractured reservoirs. Tompson et al 13 , on the other hand, deals with double porosity reservoirs for horizontal well, also through Laplace transform. Ozkan's approach 10–12 is very good method to handle complex boundaries, This paper uses this method to generate pressure response of horizontal Well under different boundaries, including infinite, single faulted, parallel, channel, and closed rectangular homogeneous and naturally fractured reservoirs. Theory Let us consider a horizontal well completed in an anisotropy medium, which is infinite in the × and y directions. kx, ky and kz denote the perrneabilities of the formation in the principle directions. Although solutions have been presented for the three-dimensional anisotropy medium, we will deal with the solution for isotropic media (k h = k x = k y and k v = k z ). We consider the flow of a single-phase, slightly-compressible fluid of constant viscosity and a horizontal well has length L in a reservoir of height h. The upper and bottom boundaries (z=O and z c =h) are assumed to be impermeable. The well is assumed to be parallel to the top and bottom boundary, and gravity effects are considered to be negligible. The origin of the coordinate system, as shown in Figure 1, is the center of the well. Initially, the pressure is uniform throughout the reservoir. For convenience, we use results in dimensionless form. Dimensionless pressure and dimensionless time are defined as:

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–9, 1998

Paper Number: PETSOC-98-71

... permeability reservoirs taking into account fracture turbulence. modeling & simulation permeability flow in porous media hydraulic fracturing wellbore

**drillstem****testing**upstream oil & gas non-darcy flow fracture half length permeability gas well guppy fractured well drillstem/well...
Abstract

Abstract Hydraulic fracturing has become increasingly popular in high permeability gas reservoirs in order to reduce apparent skin and thus improve well productivity. The remaining post fracture rate dependent skin effect varies from case to case and it is unclear whether this is a result of non-Darcy flow in the fracture, the reservoir or both. This paper presents a study of the effects of reservoir and fracture turbulence in fractured gas wells. First, a quantification of the fracture length required to eliminate the effects of reservoir turbulence is obtained by means of a numerical study. A similar study with non-Darcy flow in both the reservoir and the fracture results in a correlation of fracture length required to get zero apparent skin at 75% of AOF as a function of reservoir permeability, pressure, fracture conductivity and β factor. Introduction As shown first by Forschheimer (1901) flow through porous media deviates from the linear Darcy's law and can be described by a quadratic equation with a non-Darcy flow coefficient β in the non-linear term. The coefficient β has been correlated to reservoir permeability by numerous authors; in general β decreases with increasing reservoir permeability. Experience has shown that the non-Darcy term becomes more significant in higher permeability gas reservoirs. Generally for reservoir permeabilities below 1 mD there is little effect from non-Darcy flow. In higher permeability reservoirs non-Darcy flow can significantly restrict well production rates and may also affect the pressure transient response. Hydraulic fracturing has become increasingly popular in high permeability gas reservoirs. Normally the goal for hydraulic fracturing high permeability gas wells is to bypass skin damage and thus increase initial flow rates. These ‘skin’ fractures are generally small in nature and may or may not include high-grade proppants. Prior to performing such a treatment there is often evidence to support a high permeability reservoir and a high apparent skin. Unfortunately there is rarely enough data to distinguish if this skin is a true mechanical skin or rate dependent (non- Darcy) skin. Post fracture analysis may show apparent skins ranging from slightly stimulated to neutral to positive. If a multi-rate post fracture test was performed it is sometimes possible to separate mechanical skin from rate dependent skin. The basic problem with applying the rate dependent skin analysis to a fractured well is that the rate dependent skin was developed based on the assumption of radial homogeneous flow into the wellbore. By adding a hydraulic fracture the flow regime has been altered and the theory breaks down. It is unclear whether the rate dependent skin is occurring in the linear fracture flow or in the reservoir or in both. The primary purpose of this study was to quantify when reservoir turbulence is insignificant for a fractured well. The second purpose was to provide a simple method for predicting post fracture rates in high permeability reservoirs taking into account fracture turbulence.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–9, 1998

Paper Number: PETSOC-98-57

... enhanced recovery underbalanced drilling liquid flow rate separator return gas production monitoring nitrogen injection header point tester secondary separator separation and treating dew point injection rate gas stream operation reservoir surveillance

**drillstem****testing**THE PETROLEUM...
Abstract

Abstract Underbalanced drilling is one of today's fastest evolving technologies in the oil and gas industry. Gasified drilling fluid is most commonly used in underbalanced drilling of pressure-depleted reservoirs. Nitrogen gas, which is inert and not flammable, has been the predominant choice in underbalanced drilling operations, with relatively few operations using natural gas or compressed air. Nitrogen consumption incurs a significant (20% to 30%) portion of the overall underbalanced drilling operation cost. One option to reduce nitrogen consumption would be to recycle it. This operation involves the recovery of the return gas from the separation unit for re-compression and re-injection into the well. In most cases, the return gas is still predominantly nitrogen unless the well is a prolific gas producer. For successful implementation of gas recycling, it is essential to maintain consistent quality and rate of the return gas. The feed gas for the compressors must be sufficiently dry to ensure that any water or hydrocarbon vapors do not condense out during the compression cycle. Secondly, the return gas rate must be stable so that the gas can be re-compressed and re-injected into the well at a specified injection rate and pressure. Northland Energy Corporation with Porta-test International Inc., designed and fabricated a system to recover and re-circulate the return gas for underbalanced drilling. A comprehensive yard test was designed and implemented to test the prototype system. Initial results indicate this system is ideal for field applications, though some refinement will be necessary to realize the full benefit of such a system. Introduction One of today's fastest evolving technologies in the oil and gas industry is underbalanced drilling (UBD). Preventing drilling damage is seen to be a major contributor to well performance, especially when dealing with high cost horizontal wells. Long "pay zones" will naturally require longer drilling time, thereby extending exposure to damaging conditions. When properly designed, underbalanced drilling programs allow the circulation pressures to be within a specified range, normally just below the formation pressure. Reduced differential pressures can prevent fluid loss and reduce fines migration, thus reducing the damage to the producing formation. Furthermore, underbalanced drilling can allow drilling in highly fractured formations or pressure depleted formations which may otherwise experience fluid loss and numerous other drilling problems (i.e., stuck pipe). In most of the applications for underbalanced drilling in Canada, low formation pressures have not allowed the use of single phase liquid systems as the hydrostatic pressure would have been above the reservoir pressure. Consequently, to achieve lower pressures requires that the drilling fluid be lightened by entraining a gas in the drilling fluid. The gas is injected into the circulating drilling fluid and then recovered from the well into a closed separator where solids, liquids and gases are separated and metered. To date, the majority of Canadian underbalanced drilling operations have been undertaken using cryogenic nitrogen with liquid nitrogen supplied from air separation plants. Unfortunately many of the prime underbalanced drilling targets are located far from a source of liquid nitrogen. This results in significant costs for the transport of liquid nitrogen.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–9, 1998

Paper Number: PETSOC-98-77

... t), pressure derivative of analysis curve shows up in the late period and forms assumption phenomenon with sealing boundary. numerical laplace transformation superposition time reservoir variable rate superposition time analysis society of petroleum engineers

**drillstem****testing**buildup...
Abstract

Abstract Conventional analysis method of DST buildup period uses Agwarl's equivalent time handling variable rate. Assumption of the method is semi-log radial flow for homogenous reservoir. However for heterogeneous reservoir (double porosity, double permeability) the method will cause pressure derivative curve distortion and the pressure derivation curve cannot match type curve of conventional constant rate. This paper presents a new analysis method of DST pressure history using flow rate deconvolution in Laplace space. Through wellbore storage effect computing history rate and determined pressure response by applying Laplace deconvolution method, we can estimate parameters in Laplace space. Through simulated data and oil field data, the numerical results obtained are stable and not sensitive to noise. The established method provides a new way to understand DST pressure history in homogenous and heterogeneous reservoirs. Introduction DST is widely adopted due to its fast speed, attaining a lot of information and low cost. Particular interpretation methods of DST such as flow period analysis (Ramey 2,3,4 slug test analysis, Peres's 5 pressure integrated method), buildup period analysis (Peres's 6 pressure deconvolution, modified Horner method) and pressure history analysis are special for homogenous formation. On the other hand, the analysis theory and interpretation methods of conventional drawdown and buildup test have become mature. If DST buildup period data are converted into equivalent conventional drawdown data, conventional test analysis theory and interpretation method can be used in DST. At the present time, using variable rate superposition (Agwarl's 1 equivalent time) method can convert DST buildup data into equivalent conventional drawdown data. This method comes from variable rate superposition of semi-log radial flow behavior and it is only suitable for homogenous reservoir. According to simulated data analysis of DST, obtained data through variable rate superposition processing do not match type curve of conventional constant rate for naturally fractured reservoir. Therefore, this conventional method can not correctly estimate parameters. In this paper, according to DST full pressure history characteristic and throughout wellbore storage to calculate history rate, we can get pressure response of reservoir for constant rate and directly estimate parameters in Laplace space by numerical Laplace transformation. Application of simulated and oilfield data show that the new method is more accurate than Agwarl's method and can effectively determine estimated error of initial formation pressure. Effect of Variable Rate Superposition Time on Pressure Derivative Curve DST test simulator can be used to generate "flow and buildup", history pressure data to calculate flow period and buildup period rate. According to variable rate superposition time handling buildup period data, we can attain double-log diagnose curve and pressure derivative curve of standard drawdown response. Comparing the actual analysis curve with the standard curve, it is shown that the curve match is very good between the analysis curve of variable rate superposition time and the standard curve for infinite acting homogenous reservoir. But, if using average rate superposition time Δ t e = t f × Δ t / (t f + Δ t), pressure derivative of analysis curve shows up in the late period and forms assumption phenomenon with sealing boundary.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–9, 1998

Paper Number: PETSOC-98-86

... pressure decline analysis hydraulic fracturing upstream oil & gas performance evaluation exhibition platform fracture simulation drillstem/well testing fracture length treatment simulation society of petroleum engineers

**drillstem****testing**pressure transient testing well performance THE...
Abstract

Abstract Optimum fracturing is very important and what reservoir managers expect in order to exploitate reservoirs effectively. It is difficult to both reservoir managers and service operators to assess a treatment whether an optimum one because a underground fracture is invisible and immeasurable. Previously some individual techniques such as shut-in pressure analysis and well test after a treatment were presented in the evaluation of hydraulic fractures. However, using all the techniques in one evaluation and comparing the different results are not reported to our scope. Several evaluating techniques have been integrated and a software platform has been developed to evaluate a hydraulic fracture using recorded information during injecting and the tested data after a treatment. These techniques include treatment simulation, pressure decline analysis, transient well test and the evaluation of production performance. A case is investigated by these techniques and the comparison and comments are presented in this paper. Ability to understanding a hydraulic fracture has been improved a lot and the confidence can be enhanced in further optimum designing and treating having these integrated techniques. Introduction Economic optimum of hydraulic fracturing is what people expect in petroleum industry. To achieve this goal much work was done in past more than ten years. Veatch [1] firstly outlined the concept of optimization of hydraulic fracturing treatments on the basis of NPV(net present value). Following Veatch's study Warembourg [2] gave out the detail and general steps for optimizing hydraulic fracturing treatments. Then many applications in determining and practicing optimum fracturing have been attempted [3]-[7] and now many methods and rules to determine optimum fractures are widely used in the industry. However, although a optimum treatment or fracture can be planned very well and designed very accurately before operating it is still questionable and difficult to answer that whether a proppanted fracture is optimum and a fractured operation is the best one because a underground fracture is invisible and immeasurable directly. In addition, a practical fracture usually differs from a designed one as in-situ parameters are not completely the same as those used in the design. Therefore, the evaluation of a existing fracture or a treatment is very important to both reservoir engineers and service operators. Recent years much effort has been made in order to assess existing fractures and fracturing treatments [8]-[21] and now many evaluation methods are available. The methods include well test, pressure decline analysis, treatment simulation and performance evaluation etc.. In order to evaluate fracturing treatments and fractured fractures comprehensively, a integrated software platform called AFDDE (Acidizing & Fracturing Design, Diagnosis and Evaluation) is developed based on the above analyses, which is financially supported by service companies. This paper presents the main analysis techniques in the platform and a case application. FRACTURE EVALUATION TECHNIQUES The information feeding back from treatments and fractured fractures is treatment records (including treating pressures, rates, and pressure decline after shutting in etc.), production performance after treatments and pressure build-up or pressure down test data after treating. In according to the different information, a suitable interpreting techniques may be selected.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-32

... constant rate rodriguez constant bottom-hole pressure production rate once pseudo-steady-state one-dimensional linear flow system investigation

**drillstem****testing**differential equation one-dimensional linear flow reservoir equation upstream oil & gas drillstem/well testing one-dimensional...
Abstract

Abstract A one-dimensional linear flow system of slight compressibility and of uniform properties is considered. At each boundary the pressure is constant, below the initial value, and generally different At any time, the flow rate distribution within the system is found analytically in terms of theta functions, and the position of the drainage front is given in terms of an incomplete elliptic junction. Except for equal terminal pressures, no proportionality exists between production rates and drainage areas, probably because the time to obtain boundary dominated flow is larger than the time at which one of the rates becomes zero. Pressure buildups following shutting in one of the two ends were obtained using the rate distribution during production and the unit step-junction. Results provide insight into the significance of parameters obtained from well tests in the presence of open nearby wells. Introduction For wells producing at constant rates from a finite and homogeneous reservoir, the volume drained by each well is proportional to its production rate once pseudo-steady-state has been reached. This paper explores the relationship between drainage volumes and rates (or other parameter) for wells producing at constant bottom-hole pressure, for which no pseudo- steady-state can exist. Under the customary idealized conditions of homogeneity and uniformity of properties and single fluid flow, the drainage volumes have two unknowns: shape and size. The one-dimensional linear system chosen for analyses reduces the unknowns to one: the size of the drainage volume. In plain view, the shapes of the drainage volumes are rectangles. Rodriguez and Cinco-Ley l and Camacho et al 2 have recently considered multi-well, multi-dimensional systems producing at constant bottom-hole pressure. Their results give rise to the investigation considered here. We are unaware of any prior investigation on this subject. Model The system considered is linear in x, of length L, and having a unit cross-sectional area normal to the x-direction. There are two plane sinks (wells), one at × =0, the other at × =L, in a formation containing a single fluid having a small and constant compressibility c, and a mobility λ. The system has a uniform and homogeneous hydraulic diffusivity η, and is initially at a uniform pressure Pi . Differential Equation For the dimensionless variables defined in the Nomenclature, the differential equation and the initial and boundary conditions are Equation (1) (Available in full paper) Equation (2) (Available in full paper) Equation (3) (Available in full paper) and Equation (4) (Available in full paper) Sometimes it is advantageous to use a dimensionless time τ defined by Equation (5) (Available in full paper) Solution The solution to the differential equation (1) subject to the initial and boundary conditions given by Equations (2) - (4) is given by Carslaw and Jaeger 3 (pp 104-) to be Equation (6) (Available in full paper) The pressure may then be manipulated to obtain additional results of interest. The flow rate anywhere in the reservoir, obtained from the spatial derivative of Equation (6) and the definitions of the theta functions, is Equation (7) (Available in full paper)

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-54

... condensate reservoir

**drillstem****testing**drillstem/well testing RESERVOIR EVALUATION OF A GAS CONDENSATE RESERVOIR USING PRESSURE TRANSIENT ANALYSIS A.M.ALY W.D.MCCAIN N.C.HILL W.J.LEE this article begins on the next page F THE PETROLEUM SOCIETY PAPER 97-54 Reservoir Evaluation of a Gas Condensate...
Abstract

Abstract This paper presents a case history of characterization of a gas condensate reservoir using pressure transient analysis. Pressure transient tests from wells in this field led to test data plots with complex shapes. Specifically, the pressure derivative in a typical test flattened at intermediate shut-in times (after wellbore storage effects diminished) and then trended downward. This curve shape indicates lower mobility near the wellbore and increased mobility some distance away. Using conventional interpretation techniques, this pressure derivative response may be interpreted (erroneously) as a composite reservoir with low transmissibility in a region with radius of almost 500 feet near the well, surrounded by a region of higher transmissibility, and a positive skin factor. In this study, we modeled well tests in this field with a fully compositional reservoir simulator. We demonstrated that we can reproduce the observed test behavior in a homogenous reservoir. The decrease in pressure derivative is caused by reservoir fluid property changes with pressure, and the apparent positive skin factor is a result of liquid condensing in the formation near the wellbore. The region with reduced transmissibility (high liquid saturation) was on the order of only 20feet in radius. Our study included sensitivity analysis to determine the effect of selected variables on pressure transient test response. Production time prior to shut-in proved to be particularly important. Longer production periods prior to shut-in can modify the shape of the derivative curve plot but do not change the possible erroneous interpretations resulting from essentially perfect fits of test data with composite reservoir models. Introduction Analysis of well tests from gas condensate reservoirs is a significant challenge for engineers. If pressure drops below the dew point near the wellbore during the test, a condensate ring will accumulate immediately around the well. This can cause a significant loss in well productivity. The formation of this ring is documented by McCain and Alexander 1 . In this paper, we report an investigation of the effect of the condensate ring on pressure transient analysis and document the distinctive behavior of the pressure derivative caused by the ring. A drill stem test (DST) can include a series of production and shut-in periods, and thus can produce particularly "interesting" pressure derivative curves in gas condensate reservoirs. The test that we analyzed and discuss in this paper was from a multi-flow period, multi-shutin period DST. Although many papers discuss fluid flow in gas condensate reservoirs, we found none that propose adequate methodology to determine formation properties from analysis of well test data from gas condensate reservoirs. Bourbiaux 2 investigated depletion behavior in gas condensate wells using a parametric modeling study. Carlson and Myer 3 studied the effect of condensate drop out on the performance of fractured wells and presented some information on well test analysis of fractured gas condensate reservoirs. Afidick, et al. 4 presented a case study of a gas condensate reservoir. Jones, et al. 5 presented a two-phase analog that can be used for build up analysis from wells producing below the dew point pressure.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-68

... master valve high arctic offshore completion offshore gas subsea system drillstem/well testing situ abandonment mcbeth tri ocean engineering ltd valve subsea tree ice platform control system canada wellhead

**drillstem****testing**DRAKE F-76 IN SITU ABANDONMENT OF A HIGH ARCTIC OFFSHORE...
Abstract

Abstract The Drake F-76 well was drilled in 1978 from an ice platform, in 55 m of water, offshore Melville Island, N.W.T., Canada. The well was completed as a prototype gas producer using a subsea production tree and subsea pipeline bundle to shore. Well testing and project feasibility testing were completed by 1979 and the project suspended In 1993 a decision was made to abandon the well. An extensive program of planning, equipment refit and design was undertaken and completed over two years. Technical and environmental approvals were solicited and received from regulatory bodies. In the winter of 1995/96 the wellhead was relocated and an ice platform constructed. A selection of purpose built and contracted equipment was mobilized to site and assembled. A subsea reconnection was completed, the wellhead was successfully function and pressure tested and the well subsequently re-entered and permanently plugged. The subsea tree and associated flowline equipment were decommissioned and abandoned in-situ. This paper describes the subsea completion, the technical evaluation of the abandonment operation and the methods used to successfully abandon the installation. Introduction The Drake gas field is located on the east coast of the Sabine Peninsula, Melville Island, N.W.T. as shown in Figure I. The field, with approximately 5.7 tcf of proved and probable reserves is about 30 kms in length and straddles the coastline with the reserves distributed almost equally between land based and offshore portions of the reservoir. The land based portion of the field was explored and developed in conventional fashion in the early 1970's. While exploratory wells drilled from sea ice platforms had proven up the offshore reserves, there was a desire to develop and test production methods for this offshore gas. It was intended to show this gas could be delivered to production facilities for subsequent sale into the gas marketing projects then proposed for the early 1980's. In 1978, Panarctic Oils Ltd. successfully drilled, completed and flow tested the Panarctic Hmstd et al Drake F-76 well from a strengthened ice platform located approximately 1 km offshore Melville Island. The well was drilled to a depth of 1128 m (below kelly bushings) in water 54.9 m deep. The well was completed with a subsea production tree, two bundled 152 mm subsea flowlines to shore and gas processing and testing facilities onshore as shown in Figure 2. Remote wellhead control was provided from a shore based control unit, through subsea control lines in the flowline bundles to a control module located on the wellhead. The Drake F-76 project was designed to demonstrate that offshore gas could be delivered into a land based gathering system, through remotely operated subsea wells, despite the problems of sea ice, permafrost and generally challenging conditions. Although the project in itself was a success, no market for Arctic gas has been developed and the facilities have been dormant since 1978. Given that prospects for gas development appeared to be some years distant, Panarctic proposed to abandon these facilities and return the land lease to the Crown.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-33

... upstream oil & gas storativity ratio complex reservoir condensate reservoir fractured reservoir wellbore matrix transition period

**drillstem****testing**conventional crossplot reservoir equation fracture WELL TEST ANALYSIS OF NATURALLY FRACTURED CONDENSATE RESERVOIRS R.AGUILERA M.C.MG this...
Abstract

Abstract Approximate equations are presented for evaluation of naturally fractured gas condensate reservoirs represented by dual-porosity models in radial systems. The reader is cautioned that this work is in progress. Additional research will help to corroborate and refine these techniques. The solutions have not been published previously in the petroleum engineering literature. The solutions are presented for drawdown and buildup tests. The model assumes flow of gas condensate from a tight matrix into permeable natural fractures. The fractures conduct the fluids to the wellbore. It is preliminary shown that a conventional cross plot of m(p) vs. time on semi logarithmic coordinates results in approximately two parallel straight lines with a separation that is related to the storativity ratio between fractures and matrix. This plot allows determination of key parameters such as absolute permeability, effective permeability's to oil and gas, skin, storativity ratio (ω), fracture porosity (Φ 2 ), average distance between natural fractures (h m ), radius of investigation, and extrapolated pressure (p 1 or p). In addition the method permits generating a liquid saturation profile and a general composition profile around the wellbore at shutin. Introduction Naturally fractured reservoirs have been the object of intensive research during the last few years in the geologic as well as the engineering fields. Transient pressure analysis has received particular attention. Barenblatt and Zheltov (1) and Warren and Root (2) handled naturally fractured reservoirs by assuming pseudo steady-state (restricted) interporosity flow in a model made out of cubes with spaces in between. Flow toward the wellbore was assumed to be radial via the natural fractures. Their work led to the conclusion that a conventional cross plot of pressure vs. log of time should result in two parallel straight lines with a transition period in between. The separation of the two straight liens allowed calculation of the storativity ratio omega, i.e. the fraction of the total storage within the natural fractures. Kazemi (3) used a numerical model of a finite reservoir with a horizontal fracture under the assumption of unsteady state interporosity flow and substantiated Warren and Root's conclusion with respect to the two parallel straight lines. The transition period, however, was different due to the unsteady rather than pseudo steady-state interporosity flow assumption. de Swaan (4) developed a diffusivity equation and analytical solutions to handle the first and last straight lines. His method, however, could not analyze the transition period. Najurieta (5,6) developed analytical solutions of de Swaan's radial diffusivity equation which could handle the transition period as well as the first and last straight lines. Streltsova (7) used a gradient flow model and indicated that the transition period should yield a straight line with a slope equal to ½ the slope of the early and late straight lines. Her examples showing the ½ slopes gave values of storativity ratios approximately equal to 0.37, 0.26, and 0.48. Serra et al. (8) reached the same conclusion with the use of a stratum model for the cases in which the storativity ratio, omega, was smaller than 0.0099. Various type curves have been developed to analyze naturally fractured reservoirs with transient (9,10) and pseudo steady-state (11) interporosity flow.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-55

...-invaded regions, as well as oil and water relative permeabilities. intermediate region recovery process upstream oil & gas storativity power law fluid property exponent mobility drillstem/well testing interface intermediate region decrease

**drillstem****testing**composite reservoir...
Abstract

Abstract To analyze well test data from thermal recovery projects, reservoirs have mostly been assumed to consist of two regions with different, but uniform, reservoir and fluid properties, separated by a sharp interface. In reality, the interface separating the two regions is not sharp. Instead, there is an intermediate region between the inner and outer regions, which is characterized by a rapid, yet smooth, decline in mobility and storativity. As an improvement over the two-region model, three-region and multi-region composite reservoir models have been proposed. However, these models still have the problem of abrupt changes in mobility and storativity in the intermediate region. This paper presents a new analytical well test model for thermal recovery processes, which accounts for the smooth changes in mobility and storativity ahead of the flood front. In this study, a thermal recovery process is modeled as a three-region, composite reservoir, in which mobility and storativity in the intermediate region decrease as power law functions of radial distance from the first discontinuity boundary. This allows for smooth changes in mobility and storativity in the intermediate region. Mobility and storativity are allowed to vary with different power law (spectral) exponents. A sensitivity study is presented on the effects of the spectral exponents for mobility and storativity on the pressure derivative behavior of the composite reservoir. As well, the effect of the size of the intermediate region on the pressure behavior of a thermal recovery process is investigated. This model, which accounts for smooth changes in mobility and storativity ahead of the flood front, is a more realistic representation of a thermal recovery process than the sharp-front idealizations of the traditional two and three-region composite reservoir models currently available. It also offers a significant improvement over the multi-region, composite reservoir model by avoiding abrupt changes in fluid properties. Introduction Most of the composite reservoir models used to analyze thermal recovery well-test data consist of two regions with different, but uniform, reservoir and fluid properties, separated by a sharp interface. In reality, the interface separating the two regions is not sharp. Instead, there is an intermediate region between the inner and outer regions, which is characterized by a rapid decline in mobility and storativity. The quest to improve on the two-region, composite reservoir models, has led to the development of three-region, composite reservoir models (Onyekonwu and Ramey (l) ; Barua and Horne (2) ; and Ambastha and Ramey (3) ). In these models, the intermediate region is represented by a uniform set of mobility and storativity values that lie (in magnitude) between those in the inner region and the outer region. To represent secondary recovery processes more realistically, analytical multi-region, composite reservoir models have been proposed (Nanba and Horne (4) ; Abbaszadeh-Dehghani and Kamal (5) ; Bratvold and Horne (6) ). In these studies, analytical multi-region, composite reservoir models were used to analyze injection and pressure falloff test data following cold water injection, to yield estimates of temperature-dependent mobility's in the flooded and un-invaded regions, as well as oil and water relative permeabilities.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-35

... upstream oil & gas pressure data surface pressure response surface data pressure derivative response transducer recorder shallow gas well pressure response wellhead pressure subsurface pressure

**drillstem****testing**usefulness 76 EXAMPLES OF THE USEFULNESS AND BENEFITS OF SURFACE PRESSURE...
Abstract

Abstract This paper discusses the merits of using wellhead (surface) pressure data for pressure transient testing on a variety of oil and gas wells. The case for using wellhead pressures for pre-frac completion procedures on shallow gas wells is examined in the context of obtaining sufficient well and reservoir data within a cost-effective test program. A discussion is included regarding pressure buildup data that is collected acoustically, with illustrations of how surface pressures can measure sensitive reservoir pressure changes, even with liquid level movement above the formation. The case for considering wellhead pressures when wellbore configuration and liquid production obscures valid down-hole gauge data is presented to suggest that a ‘quiet’ side annulus may provide more accurate pressure communication with the reservoir. With recent improvements to thermal transducer compensation, a lot can now be done with surface pressure transient data. A realm that was once thought to be solely the domain of subsurface pressures data. Introduction The concept of well test analysis using surface data is not new. One of the industry's most recognized methods is the acoustic fluid level instrument that offers valuable subsurface pressure information from depth-to-liquid measurements. The sum of the casing pressure plus the hydrostatic head of the gas column pressure, plus the liquid column hydrostatic pressures are used to calculate the subsurface pressure. 1 Another recognized use of surface data for well testing is with shallow gas wells. Within Alberta, the AEUB Guide G-40 2 states that surface pressures are acceptable for dry gas wells less than 1500 m. This acceptance has proven to be very economical for the development of shallow gas reservoirs throughout Western Canada. Examples #1 and #2 show the pressure derivative response from a 325 m low density sweet gas well showing both the surface and subsurface pressure derivative response. Analytical results from both data sets are shown in Table 1 and demonstrate the validity of the technique for shallow gas wells. With the expected improvements in software program algorithms for calculations of subsurface pressures from surface pressures, it is expected that deeper wells and high flow- rate gas wells can be tested at surface 3 . At the time of writing this paper the authors have participated in over one thousand surface well tests ranging from shallow gas wells to surface pressure interference testing on both oil and gas wells. Although the title of the paper suggests that 76 examples will be shown, in actual fact, we will limit this paper to the best of 76 . Surface Pressure Recorders Perhaps the most significant development in recent years has been the proliferation of digital pressure gauges designed specifically for surface pressure transient testing, in both Canada and in the United States. Electronic surface pressure recorders are now available on the market ranging from single channel stainless steel strain gauges, to multiple channel readings and large data sampling options using silicon crystal transducers and the shear-mode, quartz crystal resonator transducers.

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-82

..., Equation (12) (Available in full paper) horizontal well flow period flow rate drillstem/well testing

**drillstem****testing**dst flow period china national star petroleum company slug flow dimensionless bottomhole pressure characteristic constant flow rate pressure analysis ofdst flow...
Abstract

Abstract By the transient pressure for horizontal well with constant flow rate and Duhamel's principle, this paper presents the method to calculate the transient pressure for DST flow period or slug flow of horizontal well, pressure analysis method of DST flow period or Slug period for horizontal well in homogeneous reservoir is given the field example is treated by this method. Introduction DST (Drill-Stem Testing) is a kind of testing method used to determine properties of reservoirs and formation fluids by switching well or opening well at the bottomhole. It also can be used to estimate the productivity of horizontal wells by DST testing before completion. There is much research about buildup test and drawdown test of horizontal wells, but there is less research about DST of horizontal well. Since that there is difference to much extent between characteristics of DST and conventional drawdown test. DST pressure analysis using conventional interpretation methods will inevitably create analytical error. DST flow period at opening well is essentially a production process on which liquid face rises in the borehole and reservoir flow rate is ever-decreasing. The flowing feature of this process is called slug flow. This paper presents method to calculate the transient pressure of DST flow periods of horizontal wells in the homogeneous reservoir based on the Duhamel's principle. Formation parameters can be estimated by automatic history matching method. Dimensionless Variables Definition Dimensionless pressure of DST flow period or slug flow for horizontal well Equation (1) (Available in full paper) Dimensionless bottomhole pressure of DST flow period or slug flow for horizontal well Equation (2) (Available in full paper) Dimensionless pressure for horizontal well with sandface constant-rate Equation (3) (Available in full paper) Dimensionless bottomhole pressure for horizontal well with sandface constant rate Equation (4) (Available in full paper) Dimensionless time Equation (5) (Available in full paper) Dimensionfess wellbore storage coefficient Equation (6) (Available in full paper) Dimensionfess flow rate Equation (7) (Available in full paper) THEORY Relationships between bottomhole flowing pressure and sandface flow rate for DST flow period or slug flow of horizontal well. In terms of the characteristic of horizontal DST flow period or slug flow, DST flow period or slug flow is a flow procession in which sandface flow rate is gradually decreasing and bottomhole flow pressure is gradually increasing. Soliman [1] has shown that in many cases transient pressure for DST flow period or slug flow is approximately given in following polynomial: Equation (8) (Available in full paper) Therefor, the sandface flow rate is: Equation (9) (Available in full paper) dimensionless form is: Equation (10) (Available in full paper) Where, Equation (10) (Available in full paper) Duhamel's principle Duhamel's principle shows the relationships between transient pressure of constant flow rate and variable flow rate. Dimensionless form of Duhamel's principle is flowing: Equation (11) (Available in full paper) Substituting Eq.10 into Eq.11 and taking the Laplace transformation, we have: Equation (12) (Available in full paper) Where, Equation (12) (Available in full paper)

Proceedings Papers

Publisher: Petroleum Society of Canada

Paper presented at the Annual Technical Meeting, June 7–10, 1997

Paper Number: PETSOC-97-51

... can be calculated, once a match has been obtained. Traditional Type Curve analysis has 2 major drawbacks: match point modern type curve analysis involve

**drillstem****testing**reservoir surveillance upstream oil & gas wellbore introduction storage derivative analysis wellbore storage...
Abstract

Abstract Modern type curve analysis involves matching the pressures and their semilog derivative on a set of dimensionless type curves, and selecting a match point. Using this point and a specified matching curve, reservoir parameters such as permeability, skin, fracture half length, fracture conductivity, etc., can be calculated. This paper shows that the same parameters can be obtained without having to use the type curves. In fact, only the semilog derivative of the data is needed on log-log coordinates. The various flow regimes such as wellbore storage, radial, linear, bilinear or spherical flow can be identified by their characteristic slopes (1, 0, 0.5, 0.25, -0.5). By simply placing a straight line with the appropriate slope fact, a combination in one single plot, of all the specialized on the (semilog) derivative points, all the required reservoir parameters can be calculated. This technique is, in actual analyses (which are traditionally done on their own individual scales, semilog, square-root, quad-root, Cartesian). In addition to the semilog derivative data, it is advisable to superimpose a plot of PPD (Primary Pressure Derivative). This enables the analyst to differentiate between reservoirs and wellbore effects, and thereby avoid some of the common pitfalls when using real (as opposed to synthetic) data. Introduction "Type Curve" analysis was used in the field of hydrology since the mid 30's. In the 70's, Ramey and his students introduced type curves to the petroleum industry, and in the early 80's Bourdet et al (1) added the "derivative", which helped in making type curve matching more unique. This article will explain how analysis of well test data can be achieved by using log-log plots and derivative, but without the need for "Type Curves". In order to understand this new procedure, a review of how Type Curve Analysis works, will first be presented, and then extended to illustrate the new methods. TYPE CURVE MATCHING: (The old way) The theory underlying Type Curve Matching is fully explained in the ERCB (now AEUB) Gas Well Testing manual (2) and Earlougher (3) . Basically the process consists of matching field data onto pre-selected dimensionless "Type Curves", and from the match point, calculating permeability, skin, wellbore storage constant, reservoir size etc.. Once a satisfactory match of the field data and the type curves has been obtained, a "Match Point" is chosen (any arbitrary point will do), and its coordinates read simultaneously from both the "Type Curve" scale and the "data" scale. From the coordinates of this arbitrary point, reservoir or wellbore characteristics can be calculated. For example to obtain permeability, read the vertical values Δp D and Δp of the dimensionless Type Curve and of the data plot, at the selected common match point. From the definition of dimensionless pressure, the calculation of permeability is easily obtained as follows: Equation (1) (Available in full paper) In a similar manner, other variables can be calculated, once a match has been obtained. Traditional Type Curve analysis has 2 major drawbacks: