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Journal Articles

Publisher: Society of Petroleum Engineers (SPE)

*SPE Res Eval & Eng*18 (02): 214–227.

Paper Number: SPE-169570-PA

Published: 14 May 2015

... for obtaining the slopes of

**beta**-derivatives for transient flow ( m t ) and BDF ( m b ) through a type-**curve**matching process. The method is validated by comparing results against oil and gas numerical simulations of vertical and hydraulically fractured vertical wells. The developed method is not biased toward...
Abstract

Summary This paper presents a new simplified method for forecasting oil and gas production during transient and boundary-dominated flow (BDF), which does not require the use of complex analytical or numerical modeling tools. The method is based on the behavior of the beta-derivative ( β ), where two approximate straight lines are obtained during transient flow and BDF with slopes m t and m b , respectively. The method is applicable not only to vertical wells in conventional reservoirs producing during BDF but also to hydraulically fractured vertical/multifractured horizontal wells in unconventional reservoirs with prevailing transient (linear) flow. Upon selection of an appropriate β B D F —which mainly depends on the type of flow regime (i.e., radial or linear)—and using the proposed equations, type curves can be generated that provide a convenient method for obtaining the slopes of beta-derivatives for transient flow ( m t ) and BDF ( m b ) through a type-curve matching process. The method is validated by comparing results against oil and gas numerical simulations of vertical and hydraulically fractured vertical wells. The developed method is not biased toward any flow regime or presence of skin. Flow regime and skin effects are embedded in the β B D F and m t parameters. Transient flow and BDF are accounted for through the slopes m t and m b , respectively. Corroborated with the use of numerical simulation and field data from the Western Canada Sedimentary Basin and Mexico, the proposed method provides reliable production-rate forecasting while staying away from the complexities of analytical or numerical modeling.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Western North American and Rocky Mountain Joint Meeting, April 17–18, 2014

Paper Number: SPE-169570-MS

... in unconventional reservoirs with prevailing transient (linear) flow. Upon selection of an appropriate β BDF (which mainly depends upon the type of flow regime, i.e., radial or linear) and using the proposed equations, type

**curves**can be generated that provide a convenient method for obtaining the slopes of**beta**...
Abstract

This paper presents a new simplified method for forecasting oil and gas production during transient and boundary dominated flow (BDF), which does not require the use of complex analytical or numerical modeling tools. The method is based on the behaviour of the beta derivative (β), where two approximate straight lines are obtained during transient flow and BDF with slopes m t and m b , respectively. The method is applicable not only to vertical wells in conventional reservoirs producing during BDF but also to hydraulically fractured vertical/multifractured horizontal wells in unconventional reservoirs with prevailing transient (linear) flow. Upon selection of an appropriate β BDF (which mainly depends upon the type of flow regime, i.e., radial or linear) and using the proposed equations, type curves can be generated that provide a convenient method for obtaining the slopes of beta derivatives for transient flow (m t ) and BDF (m b ) through a type curve matching process. The method is validated by comparing results against oil and gas numerical simulations of vertical and hydraulically fracture vertical wells. The developed method is not biased toward any flow regime or presence of skin. Flow regime and skin effects are embedded in the β BDF and m t parameters. Transient and BDF flow are accounted for through the slopes m t and m b , respectively. Corroborated with the use of numerical simulation, the proposed method provides reliable production rate forecasting while staying away from the complexities of analytical or numerical modeling.

Proceedings Papers

Publisher: NACE International

Paper presented at the CORROSION 2009, March 22–26, 2009

Paper Number: NACE-09547

... water transmission is as follows: Graphing of the

**Beta****curves**. This test included measurement of the pipe-to-rail open circuit potential Eo, and the pipe-to-soil potential Vg. These two parameters were measured during the same period of time and the values were plotted together in an x-y graph, where...
Abstract

INTRODUCTION: ABSTRACT: A large number of pipelines are routed around or through the Chicago metropolitan region of Illinois. Pipeline operators are faced with operational and maintenance challenges that include the mitigation of static and dynamic stray current interference. This interference is generated by D.C. current sources which can include foreign pipelines and DC electric rail systems. In the Chicago area, the Chicago Transit Authority (CTA) railway system is one of the sources of dynamic DC stray current that can affect pipeline operators. Preliminary testing conducted on a local 90-inch water transmission pipeline was observed to indicate the presence of dynamic stray current interference. Based on this preliminary testing, more advanced testing was initiated. Ultimately this activity lead to design services to address and mitigate the DC stray current found on this water transmission pipeline. Field testing and analysis, calculations and the final mitigation design are presented in this paper. When testing on a local 90-inch water transmission pipeline indicates the presence of dynamic stray current interference, additional confirmatory testing and design services were initiated. The focus of this work is to assess the level of stray current interference and after field testing recommend a design to help mitigate the effects of the stray dynamic DC current. DC INTERFERENCE CONSIDERATIONS AND TESTING: Existing Electrical Shielding: PIPELINE CHARACTERISTICS: The water transmission pipeline consists of approximately 9 miles of 90-inch diameter Pre-Stressed Concrete Cylinder Pipe (PCCP). The pipeline runs in the vicinity and adjacent to the CTA electric rail system. The pipeline is directly buried for the majority of the distance; however, there are two (2) sections where the pipeline is located in a tunnel. These sections are located at a point where the 90-inch pipeline is routed closest to the CTA electrical rails. Running approximately parallel to the 90-inch pipeline, but with a separation of approximately ½ a mile, is a 72-inch steel water transmission pipeline. As described above, there are two (2) sections of 90-inch water transmission pipeline which have been installed in a circular rib and lag tunnel. These tunnels are geographically the closest physical point between the CTA electric railroad and the 90-inch water transmission pipeline. The 90-inch water main as installed is not provided with any designed protection from the action of DC stray current interference. If the tunnels act to electrically isolate the 90-inch water transmission pipeline and there is no electrolyte, such as water or soil between the external pipe surface and internal tunnel surface (tunnel annulus), then stray current cannot be discharged from the pipe surface to ground within these two (2) tunnel locations. If isolated, these tunnels act to increase the electrical path resistance for the DC stray current and may act to eliminate the stray current from being discharged from the water transmission pipeline at a point which is closest to the D.C. electric rail system. These tunnels may also act to move the point of electrical interference to a point upstream or downstream of this location.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, October 9–11, 2017

Paper Number: SPE-187264-MS

... Group stratigraphy. A spectrum of simple and common

**curve**shapes, such as coarsening-upward, fining-upward, bell, funnel and cylindrical shapes can be described by two shape parameters, which are referred to as α and β, within a**Beta**distribution. A numerical method has been developed to fit a**Beta**...
Abstract

Historically, well log response and pattern matching have been used to define surface-based stratal frameworks, identify depositional facies, and distribute rock properties within subsurface geologic models. Framework surfaces are typically defined by relatively abrupt changes in lithologic trends and/or log curve shape. However, the significance, types, and locations of surfaces defined using this subjective technique can be highly variable and can result in significantly different interpretations. The semi-automated, well log pattern recognition methodology proposed here mitigates many of these inconsistencies and can yield more accurate frameworks by detecting and highlighting patterns in suites of logs that may otherwise have been missed by an interpreter. This innovative method is capable of identifying, with little or no user input, the stratal stacking pattern expressed in a typical oil-field well log suite. Furthermore, this method generates a hierarchy of surface bounded, rock packages that can used to build a consistent, repeatable stratigraphic framework for a field or basin, by removing interpreter-specific biases. This new method can detect subtle, but stratigraphically important breaks in deposition or erosion, which if ignored will result in stratal architectures with little or no predictive capability. A typical one-dimensional well log signal can be transformed into a joint, two-dimensional wavelet-scale and log-depth representation using a continuous wavelet transform (CWT). The resulting multi-scale CWT phase image of a well log exhibits (after mirroring) oval-shaped patterns that correspond surface-bounded depositional packages. The nesting and encapsulation of smaller ovals by larger ovals reveals multi-scale hierarchical patterns carried within the well log signal that is not readily apparent upon visual inspection. In order to extract the boundary information from CWT phase images, a significance-of-cone (SOC) method has been developed to quantify the significance of the smoothed cones located at the tops and bases of the CWT mirrored ovals. Ranked, hierarchical boundaries are then derived from the integration of SOC curves from all available logs each weighted according to interpreter wishes. In summary, individual CWT-derived ovals represent discrete depositional packages, while the SOC-derived surfaces may reflect the extent to which individual sedimentary packages are genetically linked or separated by discontinuities. The utility and accuracy of this automated method was tested on a suite of logs from the Mannville Group, lower Cretaceous of Alberta, Canada. Here, we compared CWT results to a subset of wells (~40 wells) from a larger dataset of >200 wells in regional cross sections that were analyzed over many months and used to define a sequence stratigraphic framework for a portion of the Mannville Group. Of the 1400+ surfaces (tops) identified using the classic, but time consuming sequence stratigraphic approach, we were able to rapidly identify and replicate 75% of the manually identified tops, generally to within ±1 meter of significant boundaries picked by the program. Furthermore, we argue that the surfaces that comprise the missing 25% may not be significant, framework building surfaces and could be ignored with little effect on the understanding of the Mannville Group stratigraphy. A spectrum of simple and common curve shapes, such as coarsening-upward, fining-upward, bell, funnel and cylindrical shapes can be described by two shape parameters, which are referred to as α and β, within a Beta distribution. A numerical method has been developed to fit a Beta distribution to diagnostic shapes observed on well log curves. Each Beta-distribution curve shape can be represented by a point on an α-β cross plot, which allows visualization of curve shape related interpretations in absolute parametric space. Well log curve shapes within and among stratigraphic units can be visualized using appropriate color coding and interactivity between a 3D or map view and the α-β cross plot. This method provides an efficient and consistent foundation for well log lithofacies distributions within stratigraphic units or zones and provides a solid foundation for interpretation of depositional facies and 3-D modeling of rock properties.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Middle East Oil & Gas Show and Conference, March 6–9, 2017

Paper Number: SPE-183860-MS

... on the understanding of the Mannville Group stratigraphy. A spectrum of simple and common

**curve**shapes, such as coarsening-upward, fining-upward, bell, funnel and cylindrical shapes can be described by two shape parameters, which are referred to as α and β, within a**Beta**distribution. A numerical method has been...Historically, well log response and pattern matching have been used to define surface-based stratal frameworks, identify depositional facies, and distribute rock properties within subsurface geologic models. Framework surfaces are typically defined by relatively abrupt changes in lithologic trends and/or log curve shape. However, the significance, types, and locations of surfaces defined using this subjective technique can be highly variable and can result in significantly different interpretations. The semi-automated, well log pattern recognition methodology proposed here mitigates many of these inconsistencies and can yield more accurate frameworks by detecting and highlighting patterns in suites of logs that may otherwise have been missed by an interpreter. This innovative method is capable of identifying, with little or no user input, the stratal stacking pattern expressed in a typical oil-field well log suite. Furthermore, this method generates a hierarchy of surface bounded, rock packages that can used to build a consistent, repeatable stratigraphic framework for a field or basin, by removing interpreter-specific biases. This new method can detect subtle, but stratigraphically important breaks in deposition or erosion, which if ignored will result in stratal architectures with little or no predictive capability. A typical one-dimensional well log signal can be transformed into a joint, two-dimensional wavelet-scale and log-depth representation using a continuous wavelet transform (CWT). The resulting multi-scale CWT phase image of a well log exhibits (after mirroring) oval-shaped patterns that correspond surface-bounded depositional packages. The nesting and encapsulation of smaller ovals by larger ovals reveals multi-scale hierarchical patterns carried within the well log signal that is not readily apparent upon visual inspection. In order to extract the boundary information from CWT phase images, a significance-of-cone (SOC) method has been developed to quantify the significance of the smoothed cones located at the tops and bases of the CWT mirrored ovals. Ranked, hierarchical boundaries are then derived from the integration of SOC curves from all available logs each weighted according to interpreter wishes. In summary, individual CWT-derived ovals represent discrete depositional packages, while the SOC-derived surfaces may reflect the extent to which individual sedimentary packages are genetically linked or separated by discontinuities. The utility and accuracy of this automated method was tested on a suite of logs from the Mannville Group, lower Cretaceous of Alberta, Canada. Here, we compared CWT results to a subset of wells (~40 wells) from a larger dataset of >200 wells in regional cross sections that were analyzed over many months and used to define a sequence stratigraphic framework for a portion of the Mannville Group. Of the 1400+ surfaces (tops) identified using the classic, but time consuming sequence stratigraphic approach, we were able to rapidly identify and replicate 75% of the manually identified tops, generally to within ±1 meter of significant boundaries picked by the program. Furthermore, we argue that the surfaces that comprise the missing 25% may not be significant, framework building surfaces and could be ignored with little effect on the understanding of the Mannville Group stratigraphy. A spectrum of simple and common curve shapes, such as coarsening-upward, fining-upward, bell, funnel and cylindrical shapes can be described by two shape parameters, which are referred to as α and β, within a Beta distribution. A numerical method has been developed to fit a Beta distribution to diagnostic shapes observed on well log curves. Each Beta-distribution curve shape can be represented by a point on an α-β cross plot, which allows visualization of curve shape related interpretations in absolute parametric space. Well log curve shapes within and among stratigraphic units can be visualized using appropriate color coding and interactivity between a 3D or map view and the α-β cross plot. This method provides an efficient and consistent foundation for well log lithofacies distributions within stratigraphic units or zones and provides a solid foundation for interpretation of depositional facies and 3-D modeling of rock properties.

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**Published:**12 November 2018

Images

**Published:**12 November 2018

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 28–30, 2015

Paper Number: SPE-175021-MS

... consider the following elements: — The tortuosity ( i.e. , the actual length to ideal length ratio) — The tendency to branch (or split). — The number of branching stages — the number of branches was held constant for a given set of cases. Comparison of the mass rate and

**beta**mass rate...
Abstract

This study introduces a novel approach to model the hydraulic fractures in a shale reservoir using a common stochastic method called “random-walk.” The goal of this work is to capture part of the “complexity” of a fracture/fracture network that has been generated by a hydraulic fracturing treatment and to attempt to characterize this fracture network using reservoir performance signatures. The steps involved in this work are: Stochastic generation of a “random-walk” fracture pattern constructed as a scaled numerical model. Assessment of the “random-walk” fracture using sensitivity analyses which consider the following elements: — The tortuosity ( i.e. , the actual length to ideal length ratio) — The tendency to branch (or split). — The number of branching stages — the number of branches was held constant for a given set of cases. Comparison of the mass rate and beta mass rate-derivative performance of the various “random-walk” fracture cases compared to the “standard” model of a planar fracture. The primary results of this work are: Generation of pressure distributions (maps) at given times ( i.e. , “time slices”) to qualitatively assess each complex-pattern during transient production. The pressure distribution figures ( i.e. , maps) are used to qualitatively determine the presence of fracture interference(s) and to identify a time interval where those interferences occur. Creation of a graphical correlation of reservoir performance in terms of cumulative recovery as a function of the fracture volume and “fracture complexity” ( i.e. , the number of branches). Creation of an empirical correlation between the number of branches in a given fracture pattern and the value of the mass rate beta-derivative during transient flow (we observed that the mass rate beta-derivative is essentially constant during transient flow regardless of the fracture network configuration, as such this constant value of the mass rate beta-derivative was selected for correlation). This work provides an alternative description of hydraulic fractures in unconventional shale-gas reservoirs which, in concept, captures the complexity of the hydraulic fracture as a stochastic fracture network. Early-time rate performance is believed to be an indicator of the geometry of the hydraulic fracture pattern. A fracture with a higher level of “complexity” yields higher values of mass rate beta-derivative when the fractures components are interfering with each other. Therefore, mass rate curves could be used as a diagnostic tool that helps the identification of the fracture geometric features.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 24–27, 2006

Paper Number: SPE-102715-MS

... Abstract The subject of non-Darcy flow in hydraulically fractured wells has generated intense debates recently. One aspect of the discussion concerns the inertia resistance factor or the so-called

**beta**factor ß in the Forchheimer equation and whether the**beta**factor ß for a proppant pack...
Abstract

Abstract The subject of non-Darcy flow in hydraulically fractured wells has generated intense debates recently. One aspect of the discussion concerns the inertia resistance factor or the so-called beta factor ß in the Forchheimer equation and whether the beta factor ß for a proppant pack should be constant over the range of flow rates of practical interests. The problem was highlighted in a recent discussion by Batenburg and Milton-Tayler 1 and the reply by Barree and Conway 2 regarding paper SPE 89325 3 in the JPT in August 2005. To properly assess all the arguments and to get a better understanding of the state-of-the-art on non-Darcy flow in porous media in general, literature concerning the theoretical basis of the Forchheimer equation and experimental work on the identification of flow regimes is reviewed. These areas of work provide insights into the applicability of the Forchheimer equation to conventional oilfield flow tests for proppant packs. Models for flow beyond the Forchheimer regime are also suggested. Introduction The effect of non-Darcy flow as one of the most critical factors in reducing the productivity of hydraulically fractured high rate wells has been documented extensively with examples of field cases 3–7 . The inertia resistance factor or the so-called beta factor b, a parameter in the Forchheimer equation for quantifying the non-Darcy flow effect, is now routinely measured for proppant packs. Nevertheless, how to derive the beta factor b from experimental data is still controversy. In a recent issue of the JPT in August 2005, there was a discussion by Batenburg and Milton-Tayler 1 and the reply by Barree and Conway 2 regarding paper SPE 89325 3 on whether the beta factor ß for a proppant pack should be constant over the range of flow rates of practical interests. The so-called non-Darcy flow in porous media occurs if the flow velocity becomes large enough so that Darcy's law 8 for the pressure gradient and the flow velocity, i.e., (1) is no longer valid. In Eq. 1, permeability k is an intrinsic property of porous media. To describe the nonlinear flow situation, a quadratic term was included by Dupuit 9 and Forchheimer 10 to generalize the flow equation, i.e., (2) Eq. 2 is commonly known as the Forchheimer equation. In the discussion of Batenburg and Milton-Tayler 1 and Barree and Conway, 2 it was presumed that non-Darcy flow in their experiments can be described by the Forchheimer equation. According to the convention of the oil and gas industry, the beta factor ß is generally deduced experimentally from the slope of the plot of the inverse of the apparent permeability 1/ k app vs. a dimensional pseudo Reynolds number " V /µ (also called the Forchheimer graph). The apparent permeability k app is defined as, (3) after rewriting the Forchheimer equation. Based on the linear correlations obtained between 1/ k app and ?? V /µ (see Fig. 1), Batenburg and Milton-Tayler 1 concluded that the beta factor ß is constant for the range of flow rates of practical interests. It was recognized that the correlation, however, does not reduce to the inverse of Darcy permeability 1/ k , when extrapolated to zero velocity. Barree and Conway, 2 on the other hand, obtained a nonlinear concave down curve shape for the variation of 1/ k app vs. ?? V /µ (see Fig. 2) and concluded, therefore, that the beta factor ß is not constant over the range of investigation. It was argued that the fact that a linear correlation does not reduce to 1/ k at zero velocity indicates that the correlation is insufficient.

Journal Articles

Journal:
Journal of Petroleum Technology

Publisher: Society of Petroleum Engineers (SPE)

*J Pet Technol*28 (10): 1180–1183.

Paper Number: SPE-5852-PA

Published: 01 October 1976

... reduction in computer time. The composition parameter and fluid properties required by the

**beta**-type simulator were obtained from a linear cell- to-cell model. 2 The parameter was plotted vs the fluid properties, and the result was a set of**curves**for each fluid property that was independent of cell number...
Abstract

JPT Forum articles are limited to 1,500 words including 250 words for eachtable and figure, or a maximum of two pages in JPT A Forum article maypresent preliminary results or conclusions of an investigation that theauthor wishes to publish before completing a full study; it may impartgeneral technical information that does not warrant publication as afull-length paper. All Forum articles are subject to approval by an editorial committee. Letters to the editor are published under Dialogue, and may cover technical or nontechnical topics. SPE-AIME reserves the right to edit letters for style and content. Introduction Cook et al. presented a modified beta-type reservoirsimulatorforapproximatingcompositionaleffectsduring simulation of dry-gas injection into an oil orrich-gas-condensate reservoir. A composition parameterrepresenting the cumulative volume of dry gas per volume of oil(G) was incorporated into a standard beta-type simulator to make that simulator behave as a compositional modelwith a reported substantial reduction in computer time.The composition parameter and fluid properties requiredby the beta-type simulator were obtained from a linear cell-to-cell model. The parameter was plotted vs thefluid properties, and the result was a set of curves for eachfluid property that was independent of cell number in thelinear model. Therefore, the curves would beindependent of the space dimension in a reservoir model.This was important because incorporating position-dependentcurves into a beta-type model would significantly complicate this model, resulting in a loss of model simplicityand computer-time advantage. The cell-to-cell model used by Cook et al.incorporated K values that were a function of pressure only; theK values were independent of fluid composition. Theauthors suggested their model for simulation of drygas injection. However, the results presented are for arelatively rich gas (9.3 1-percent C -C). Compositiondependence of K values would be minimal for this gas, which supports the fair agreement between performancepredicted by the modified beta-type model and thecompositional model. For complex fluid systems, such as dry-gas injectioninto a volatile oil or a rich-gas condensate, K values arehighly dependent on fluid composition. This paperpresents results demonstrating that composition-dependent K values yield fluid properties that are dependenton cell number or location within the reservoir.Consequently, the modified beta-type model should not be usedfor reservoir simulations where large changes in fluidcomposition are anticipated. Discussion A study was initiated to determine the effects ofcomposition-dependent K values on reservoir propertiesduring dry-gas injection into a volatile oil reservoir.The gas and oil compositions and their physical properties aregiven in Table 1. A cell-to-cell model, similar to the oneused by Cook et al., was used to obtain the compositionparameter. Gi, and the phase properties. This modeldiffered from Cook et al.'s, however, in that it used theRedlich-Kwong equation of state matched experimentallyequilibria. The equation of state matched experimentallydetermined volumetric data of the volatile oil and ofmixtures of a lean gas with the gas condensate thatis in equilibrium with this oil at reservoir conditions, The matching of these volumetric data results incomposition-dependent K values; and to match thesedata, composition-dependent K values were predicted by the equation of state. These results suggest the equationof state can be used to simulate dry-gas injection into thevolatile oil. The computation logic of the cell-to-cell model hasbeen presented in Refs. 4 and 5. Each cell of the modelused in this study contained 1 bbl of equilibrated reservoiroil at the reservoir temperature of 265 deg. F and a pressure of4,000 psia. JPT P. 1180^

Journal Articles

Journal:
Journal of Petroleum Technology

Publisher: Society of Petroleum Engineers (SPE)

*J Pet Technol*34 (11): 2517–2522.

Paper Number: SPE-11331-PA

Published: 01 November 1982

... technology

**curved**conductor bar schedule power plant**beta**field asset and portfolio management penetration earthquake offshore southern california subsea system module The**Beta**Field Development Project Robert C. Visser, * SPE, Shell Oil Co. Summary This paper summarizes the design...
Abstract

Summary This paper summarizes the design and the construction of platforms, facilities, and pipelines for the Beta field, offshore southern California. The field was discovered during the summer of 1976.The first phase of field development, consisting of bridge-connected drilling platform Ellen and production platform Elly in 265 ft (81 m) of water, has been platform Elly in 265 ft (81 m) of water, has been completed, and the field is on production. These are large platforms. The production platform includes a large platforms. The production platform includes a large power-generation plant to provide power for lifting power-generation plant to provide power for lifting low-gravity crude oil with submersible bottomhole pumps. Design and siting of the platforms provided unusual challenges because of the steeply sloping bottom and the earthquake environment.Major components of the platforms were fabricated in widely scattered locations. Both jackets were fabricated in Malaysia and the drilling and production deck modules were fabricated in Japan. Other major components were fabricated in Washington, California, Texas, and Louisiana. This paper describes the unique project control and management techniques employed to project control and management techniques employed to keep the project on schedule and within budget. Introduction The Beta field is located offshore southern California in the Gulf of Santa Catalina (Fig. 1). Located about 9 miles (14 km) from shore, the field is about 5 miles (8 km) long and less than 1 mile (1.6 km) wide. Estimated recoverable reserves under the portion of the field we operate total about 150 million bbl (24×10(6) m3) oil. The oil accumulation is shallow, ranging from 2,700 to 5,000 ft (800 to 1500 m). The oil is heavy, with crude gravities ranging from 11 to 22API (0.99 to 0.98 g/cm3). There is little or no experience producing this type of heavy oil offshore.Water depth over our portion of the field ranges from 200 to 1,000 ft (60 to 300 m). This steeply sloping bottom necessitated a complex platform siting study to optimize reservoir recovery as a function of number and location of platforms and attendant reach and cost of development wells.Optimal development will be accomplished with an 80-well capacity drilling platform, Ellen, in 265 ft (81 m) of water and a future 60-well capacity drilling platform, Eureka, in 700 ft (215 m) of water. The platform, Eureka, in 700 ft (215 m) of water. The shallow-water platform has 30 curved conductors, and the deepwater platform will have 35 curved conductors. Wells will be drilled at angles up to 80. A single production platform, Elly, installed along with the initial drilling platform, Elly, installed along with the initial drilling platform handles all the field's production. platform handles all the field's production. The first phase of development is now complete. Development drilling began in Aug. 1980 and production began in Jan. 1981. The short time needed to bring this field on production is a remarkable accomplishment, particularly in view of the many time-consuming permits particularly in view of the many time-consuming permits required for this offshore California location. Project Description Project Description The initial development of the Beta field consisted of installing drilling platform Ellen and production platform Elly. The two platforms (Figs. 2 and 3) are connected by a bridge 200 ft (61 m) long.The eight-leg drilling platform has slots for 80 wells. The platform has two modified API drilling rigs capable of drilling to 25,000 ft (7600 m). Each rig is completely self-contained with its own power plant. Conductors for 60 wells were installed by driving before drilling started. Thirty of these are curved conductors with a built-in curvature of 6 per 100 ft (30 m). The large number of curved conductors is necessary to reach the edge of the field with the limitation of 80 hole angle and the shallow depth of the reservoir. Without the use of the curved conductors, at least one more drilling platform would have been needed to develop the field fully. JPT p. 2517

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, October 3–6, 1993

Paper Number: SPE-26602-MS

... (1960) showed

**beta**independent of fluid pressure up to 2000 psi in porous discs. It is now generally accepted that the inertial pressure losses are due to secondary flows which arise from the necessarily curvilinear path taken by the fluid. A similar effect occurs in**curved**helical tubes (White, 1929...
Abstract

SPE Member Abstract Preliminary results of an experimental programme to determine the significance of dual phase flow in propped fractures are presented. Gas-water flows are considered. The results demonstrate that, even in cases of minimal water production, effective permeabilities may typically be reduced by a factor of 2, or more. In severe cases of water production, permeabilities may be less than 20% of their single phase values. Introduction Single Phase Flow In calculating the apparent permeability of a propped fracture to high rate gas flow, non-Darcy or inertial effects must be taken into account. Many studies (for example, Ergun (1952), Milton-Tayler (1993)) have shown that the Forchheimer equation gives an excellent description of the relationship between pressure losses and velocity: … [1] where P/L is pressure drop per unit length, , , p are fluid viscosity, superficial velocity (flow rate/gross pack flow area) and density and , k are the Beta Factor and Absolute Permeability respectively. The Beta Factor has been shown to be fluid independent: By Cooke (1973) to oil, gas and brine, and by Miton-Tayler (1993) to argon, helium and nitrogen. Weger (1960) showed beta independent of fluid pressure up to 2000 psi in porous discs. It is now generally accepted that the inertial pressure losses are due to secondary flows which arise from the necessarily curvilinear path taken by the fluid. A similar effect occurs in curved helical tubes (White, 1929). A transition in beta has been identified up to pv/ 15 after which beta appears to be a constant (Martins et al, 1990). P. 915^

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Unconventional Gas Recovery Symposium, May 16–18, 1982

Paper Number: SPE-10837-MS

... permeability and porosity) is made. Schematically, the total reservoir system is partitioned into domains R 1 and R 2 as shown in Figure 1.Basic attributes of R 1 and R 2 are contained in the set {K,

**beta**, P, V} where K = permeability,**beta**= porosity, P = pressure, V = volume of gas. It will be assumed...
Abstract

The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA, May 16–18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206. Abstract Several studies on production decline curves have shown that an exponential or hyperbolic curve adequately fits production decline data for Devonian shale wells. Attempts to characterize the production decline based on open flows, rock pressures, and specific shale production mechanisms have also been made. This paper seeks to provide a genesis of the decline curves with the use of a simple hydrodynamic analogy. Some physical factors critical to well productivity are also examined. physical factors critical to well productivity are also examined Introduction Production from Devonian shale wells is generally characterized by low production rates and large production timespans. Wells with continued production rates and large production timespans. Wells with continued production of over 25 years are rather common, and some wells with over 50 production of over 25 years are rather common, and some wells with over 50 years of production are still producing. However, with production rates being relatively low an average well might only produce around 300 MMCF in about 20 years or more. Increasing production rates, on a per well basis, not only adds to gas supplies but also enhances the economic viability of producing more in less time. producing more in less time. It is often desirable to estimate well productivity based on readily measurable variables during the initial stages. Initial open flows and rock pressures might be used, but these do not necessarily signal long-term well performance. This clearly is the case as in some of the observations which appear in Table 1. These observations reveal that productivity may be sensitive to physical factors, other than open flows and rock pressures, which cannot perhaps be measured directly. Given that relatively low open flows and rock pressures do not necessarily imply low productivity, it will be necessary to analyze the generating mechanism of production decline curves for possible clues. Merely graduating production decline data by various curve fits is not in itself sufficient to understand the mechanism. A possible hydrodynamic analogy is used to obtain some insights. THE HYDRODYNAMIC ANALOGY A detailed treatment of geological reservoirs is not intended here. Precise reservoir configurations including fracture geometry (shape, size Precise reservoir configurations including fracture geometry (shape, size and spatial orientation), structural, lithologic and other geologic features are not addressed. However, the broad division between the gas-generating shale matrix (lower permeability and porosity) from gas-filled fractures, fissures, sandstones, siltstones and other sources (higher permeability and porosity) is made. Schematically, the total reservoir system is partitioned into domains R 1 and R 2 as shown in Figure 1.Basic attributes of R 1 and R 2 are contained in the set {K, beta, P, V} where K = permeability, beta = porosity, P = pressure, V = volume of gas. It will be assumed that flow takes place, and has taken place over geologic time, from domain R 1 to R 2. Flow to the wellbore is place over geologic time, from domain R 1 to R 2. Flow to the wellbore is from R 2.The hydrodynamic analogy is that of two circular cylinders containing liquid that are interconnected with inlets (sources) and outlets (sinks), as shown in Figure 2.Q 1 is outflow (sink) from R 1 but inflow (source) to R 2; C 1 (capacitance) is uniform cross-sectional area; h 1 (t) is pressure at time t at the boundary, which is proportional to the height of liquid; is resistance to flow at the boundary separating R 1 from and is a measure of the permeability in the region of the boundary. Similar interpretations hold for the R 2 reservoir. A first-order equivalence relationship between pressure-volume (PV) initial conditions in the actual reservoirs with the analog cylinder "reservoirs" could be theoretically established. p. 427

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Canadian Unconventional Resources Conference, November 15–17, 2011

Paper Number: SPE-148976-MS

... enough to restrict the use of software "

**curve**fitting". However, triangular distributions are considered weak by some in that they overweight probabilities towards the tail ends of the distribution. Therefore, in this study,**beta**distributions were used to allow for the existence of very low probability...
Abstract

The Horn River Basin of northeastern British Columbia, Canada, contains natural gas in three Devonian shale units. Isopachs, depths, and net-to gross-pay ratios were determined from well logs for the Muskwa, Otter Park, and Evie Shales and then gridded. Pressure gradients were determined from well test and production data and then gridded into a single grid shared between shales. Because grid points were shared between each grid, volumetric and adsorbed gas equations could be integrated into each grid point. Static values or distributions could then be applied to equation variables and Monte Carlo simulations run to determine probabilistic gas in place (GIP) and marketable resources for each grid point, which were then summed for each shale. Grid points for the isopach and depth maps were treated as static values in the equations while net-to-gross and pressure gradient grid points became most likely values in Beta distributions where end points were assigned using regional low and high values. Most non-mapped variables in the equations were filled with Beta distributions based on typical values in the area and then applied across the basin without any local variations. On each distribution, whether based on mapped or unmapped variables, a second, overlying distribution was applied on a basin scale. This made entire iterations run a full range from pessimistic to optimistic. A few non-mapped variables in the equations were given static values. Recoverable gas resources were estimated by applying a recovery factor to free GIP estimates. Recoverable volumes from adsorbed GIP estimates were determined from a recovery factor applied to the portion of gas that would desorb during production as pressure decreased to the assumed well abandonment pressure. To determine marketable gas, gas impurities and fuel gas that would be used for processing and transport were estimated and subtracted from the recoverable estimates. Further, certain lower quality areas of the basin were excluded from the assessment, based on a low likelihood of being developed. The Horn River Basin shales are estimated to contain 10 466 10 9 m 3 (372 Tcf) to 14 894 10 9 m 3 (529 Tcf) of GIP with the expected outcome of 12 629 10 9 m 3 (448 Tcf). The marketable resource base is expected to be 1 715 10 9 m 3 (61 Tcf) to 2 714 10 9 m 3 (96 Tcf), with an expected outcome of 2 198 10 9 m 3 (78 Tcf).

Journal Articles

Journal:
SPE Production & Operations

Publisher: Society of Petroleum Engineers (SPE)

*SPE Prod & Oper*2 (04): 331–338.

Paper Number: SPE-14206-PA

Published: 01 November 1987

... rock formations were first published by Cornell and Katz. The non-Darcy flow coefficient was correlated with absolute permeability by Janicek and Katz for various limestone, dolomite, and sandstone rocks with porosity as a parameter. They found that

**beta**decreased with increasing permeability...
Abstract

Summary. The results of an experimental research program to investigate the effects of immobile liquid saturations on the non-Darcy flow coefficient are presented. Sandstone cores of absolute permeabilities ranging from 50 to 800 md were used to investigate non-Darcy flow phenomena under multiphase conditions. Immobile liquid saturations were phenomena under multiphase conditions. Immobile liquid saturations were varied from 8 to 30% PV. The multiphase experiments were conducted with N2 gas as the flowing phase and glycerin as the immobile liquid phase. It was found that the non-Darcy flow coefficient for the multiphase case may be estimated with a dry-core non-Darcy-flow-coefficient/permeability relationship developed for the rock in question and the effective gas permeability at a given saturation. permeability at a given saturation. For the immobile multiphase cases, the non-Darcy flow coefficient consistently increased with increased saturation. The experimental data obtained from this research were compared with the limited multiphase data in the literature. Where comparisons could be made, the data reported in this paper agreed favorably with the existing published data. An analysis of the experimental data revealed that a unique relationship existed between the non-Darcy flow coefficient and the effective gas permeability, porosity, liquid saturation, and effective overburden permeability, porosity, liquid saturation, and effective overburden pressure at a given temperature. pressure at a given temperature. Correlations were developed from this analysis to predict the non-Darcy flow coefficient as a function of rock and fluid properties. Where possible, the correlations were used to predict the non-Darcy coefficient possible, the correlations were used to predict the non-Darcy coefficient measured by other researchers and were compared with the dry-core correlations developed by Janicek and Katz and with a theoretical equation developed by Geertsma. Introduction Fluid flow through porous media is normally described by Darcy's equation. Darcy's equation applies as long as the fluid velocity is low enough to neglect inertial effects. When fluid velocities are large, inertial effects become significant, and a modification of Darcy's equation is necessary. The modified equation has been adequately described by Forchheimer and is expressed as ....................(1) The coefficient is called the inertial resistance coefficient, non-Darcy flow coefficient, or turbulence factor. The magnitude of determines the amount of deviation from Darcy's equation. At low flow rates, Eq. 1 reduces to Darcy's equation. Values for the non-Darcy flow coefficient from various rock formations were first published by Cornell and Katz. The non-Darcy flow coefficient was correlated with absolute permeability by Janicek and Katz for various limestone, dolomite, and sandstone rocks with porosity as a parameter. They found that beta decreased with increasing permeability and porosity. Their correlation is shown in Fig. 1. In 1969, Gewers and Nichol developed a similar non-Darcy-flow- coefficient/permeability correlation for microvugular carbonate rocks. For this rock type, non-Darcy flow coefficient values were found to be an order of magnitude higher than values predicted by the Janicek-Katz correlation. This was attributed to the high degree of inhomogeneity in the microvugular cores used in this study. Gewers and Nichol also attempted to determine the effect of an immobile liquid on the non-Darcy flow coefficient. Glycerin was used as the liquid phase at saturations of 10, 20, and 30% PV. At saturations of 20 and 30% PV, the non-Darcy flow coefficient varied approximately as their correlation of dry-core beta vs. permeability. At a saturation of 10% PV, the non-Darcy flow coefficient decreased noticeably. This effect is shown in Fig. 2. Gewers and Nichol attributed this effect to the streamlining of the porous matrix and blocking of the narrow channels at this level of saturation. Wong extended the work of Gewers and Nichol by examining the effect of a mobile water saturation on the non-Darcy flow coefficient for the microvugular carbonate rock. Wong found that values of the non-Darcy flow coefficient increased by as much as 800% when the liquid saturation increased from 40 to 70% PV. The non-Darcy flow coefficient was measured at saturations of 45, 60, and 70% PV and followed the trend of immobile beta values given by Gewers and Nichol. Wong concluded that two-phase systems may be approximated by use of the effective permeability to gas at a given saturation and a correlation of dry-core non-Darcy-flow-coefficient/ permeability relationship for the rock in question, although no permeability relationship for the rock in question, although no data or theory was presented to support the hypothesis. Attempts have been made to correlate rock properties with the non-Darcy flow coefficient and to incorporate the correlation into an equation that can be applied to various porous media. Cook measured the non-Darcy flow coefficient for packed fractures and plotted a non-Darcy-flow-coefficient/permeability relationship for different sand sizes. The curves were of the form (2) where k is in darcies and the constants a and b are sand-size dependent. A table of values of a and b for various sand sizes is included in Ref. 4. A subsequent investigation, however, points out that Eq. 2 is dimensionally incorrect. Geertsma developed an equation for the prediction of non-Darcy flow coefficients in porous media using dimensional analysis and experimental data to obtain (3) Geertsma hypothesized further that Eq. 3 could be modified to account for an immobile liquid saturation according to (4) Koh investigated the magnitude of the non-Darcy coefficient for gas flow through propped fractures with respect to closure pressure and proppant concentration. pressure and proppant concentration. SPEPE P. 331

Proceedings Papers

Publisher: Offshore Technology Conference

Paper presented at the Offshore Technology Conference, May 4–7, 1981

Paper Number: OTC-4140-MS

...OTC 4140 THE

**BETA**FIELD DEVELOPMENT PROJECT by Robert C. Visser, Shell Oil Company ©Copyright 1981 Offshore Technology Conference T~is paper was presen!ed at the 13th Annual OTC in Houston, TX, May 4-7,1981. The material Is subject to correction by the author. Per- mISSion to copy IS restncted...
Abstract

Abstract This paper summarizes the design and construction of platforms, facilities and pipelines for the Beta field, offshore Southern California. The field was discovered by Shell and its partners during the summer of 1976. The first phase of field development consisting of bridge-connected drilling platform Ellen and production platform Elly in 265 feet of water has been completed and the field is on production. These are large platforms. The production platform includes a large power generation plant to provide power for lifting low gravity crude oil with submersible.bottom hole pumps. Design and siting of the platforms provided unusual challenges due to the steeplysloping bottom and the earthquake environment. Major components of the platforms were fabricated in widely scattered locations. Both jackets were fabricated in Malaysia and their ocean tows set world records. Drilling and production deck modules were fabricated in Japan. Other major components were fabricated in the states of Washington, California, Texas and Louisiana. The paper describes the unique project control and management techniques employed to keep the project on schedule and within budget. Introduction The Beta field is located offshore Southern California in the Gulf of Santa Catalina, see Figure 1. The field was discovered in mid-1976 by the Shell-Occidental-Aminoil-Santa Fe Energy Hamilton group with Shell as the operator. Located about nine miles from shore, the field is about five miles long and somewhat less than a mile wide. Estimated recoverable reserves under the Shell operated portion of the field total about 150 million barrels of oil. The oil accumulation is shallow, ranging from 2700 to 5000 feet. The oil is heavy with crude gravities ranging from 11 to 22 degrees API. Little or no experience exists producing this type of heavy oil offshore Water depth over the Shell operated portion of the field ranges from 200 to 1000 feet. This steeplysloping bottom necessitated a complex platform siting study to optimize reservoir recovery as a function of number and location of platforms and attendant reach and cost of development wells. Optimum development will be accomplished with an eighty well capacity drilling platform, named Ellen, in 265 feet of water and a future 60 well capacity drilling platform, named Eureka, in 700 feet of water. The shallow water platform has 30 curved conductors and the deep water platform will have 35 curved conductors. Wells will be drilled at angles up to 80 degrees. A single production platform, named Elly, installed along with the initial drilling platform handles all of the field's production. Phase one of the development is now complete. Development drilling started in August 1980 and production commenced in January 1981. The short time needed to bring this field on production is a remarkable accomplishment, particularly in view of the many time consuming permits that were required for this offshore California location.

Proceedings Papers

Publisher: NACE International

Paper presented at the CORROSION 2006, March 12–16, 2006

Paper Number: NACE-06224

.... Also of note is Schutz and Xiao?s study of hydrogen absorption of

**beta**titanium alloys Ti-Grade 19 (Ti-3Al-8V-6Cr-4Zr-4Mo), Ti-Grade 20 (Ti-3Al-8V-6Cr-4Zr-4Mo-Pd), and also an additional version of Grade 20 + Ru, which showed that these PGM additions did not aggravate hydrogen absorption in boiling HCl...
Abstract

ABSTRACT The hydrogen absorption tendencies of several platinum group metal (PGM) enhanced titanium alloys were investigated. The short-term (24-240 hour) tests were conducted in hydrochloric acid (HCl) solutions that were partially deaerated or naturally aerated, at subboiling or boiling temperatures. Coupons were sampled before and after each test exposure to determine hydrogen content and corrosion rate. The hydrogen uptake was used to determine the hydrogen uptake efficiency for each alloy under each set of conditions. Based on the tests conducted, the effects of temperature, dissolved oxygen content, and alloy content were evaluated and are discussed. INTRODUCTION The following is a comparison of the hydrogen absorption tendencies of commercially pure (C.P.) titanium (Grades 1, 2), Ti-0.15Pd (Grades 7, 11), Ti-0.1Ru (Grade 27), Ti-0.5Ni-0.05Ru (Grade 13), Ti-0.05Pd (Grade 16), Ti-3Al-2.5V-0.1Ru (Grade 28) and Ti-0.4Ni-0.15Cr-0.015Pd- 0.025Ru (Grade 33). The evaluation was done by conducting weight loss tests in boiling and sub-boiling naturally aerated and partially deaerated HCl solutions, and measuring the weight loss and hydrogen content of the coupons before and after each test. The data obtained was used to determine a corrosion rate, and hydrogen uptake efficiency (HUE) for each alloy in each set of test conditions in order to determine which alloys were more prone to hydrogen absorption. The mechanism of passivation for platinum group metal (PGM) enhanced titanium alloys is due to the modification of the cathodic hydrogen evolution reaction (HER). PGM additions are useful in this regard because they provide a high cathodic exchange current density for the HER and a lower cathodic Tafel slope. This is in contrast to C.P. titanium, which has a low cathodic exchange current density for the HER and a higher cathodic Tafel slope. The PGM additions act as cathodic depolarizers and create a mixed potential in the passive range. For these alloys, the potential is shifted in the noble direction and the cathodic (HER) reaction on the PGM enhanced Ti intersects the anodic polarization curve at a potential positive to its anodic loop or critical anodic current density and in its passive region. Evans? diagrams illustrating this effect are shown in References 1 and 3. Several investigators have studied the effects of PGM additions on hydrogen absorption of titanium alloys in reducing acids. A review on the subject of hydrogen absorption of Ti, Ti- Grade 12 and PGM enhanced Ti as related to hydrogen induced cracking (HIC) is given by Hua et al. Fukuzuka found that Pd enhanced alloys may be more prone to hydrogen absorption than unalloyed titanium. Bishop reported that C.P. titanium and Ti-0.2Pd were similar with respect to hydrogen absorption tendencies in cathodic charging experiments. In HCl weight loss studies, the Ti-0.2Pd alloy was much less susceptible to hydrogen absorption. Sedricks has reported that Ru enhanced titanium alloys are less prone to hydrogen absorption. Also of note is Schutz and Xiao?s study of hydrogen absorption of beta titanium alloys Ti-Grade 19 (Ti-3Al-8V-6Cr-4Zr-4Mo), Ti-Grade 20 (Ti-3Al-8V-6Cr-4Zr-4Mo-Pd), and also an additional version of Grade 20 + Ru, which showed that these PGM additions did not aggravate hydrogen absorption in boiling HCl suggesting that the oxide film further presented a barrier to atomic hydrogen. The effects of these PGM additions on the metallurgy of the binary Ti-Ru and Ti-Pd alloys have also been investigated. Palladium additions to titanium in Ti-0.15Pd alloys lead to the formation of a Ti2Pd compound. In contrast to these Pd alloys, Ti-0.1Ru alloys form a large number of beta phase particles which are much more e

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Canadian Unconventional Resources Conference, November 15–17, 2011

Paper Number: SPE-149361-MS

... with a unit slope. Figure 2

**Beta**-derivative plots for the two production scenarios The separation in the**curves**during the boundary-dominated flow regime can be explained from analytical solutions. Equations (3) and ( 4 ) are, respectively, the solutions for constant rate and constant pressure...
Abstract

This paper presents a new insight into rate transient analysis using the beta-derivative function (β-derivative). Production rates and flowing pressures from tight gas and shale gas wells were analyzed using various implementations of the betaderivative to emphasize different features of the data and, as a result, reveal characteristic information about flow regimes and the extent to which the reservoir has been drained. The beta-derivative was applied to rate, pressure and normalized rate, and the effect of skin on the β-derivative was also investigated. The intent was to determine which format is the most useful for diagnosing the dominant flow regimes or the sequence of flow regimes that have occurred while producing from an unconventional hydrocarbon reservoirs (tight gas, shale gas and light tight oil). It was found that the classic signature of the β-derivative is altered by the presence of skin. Also, the derivative based on constant rate is different from that based on constant pressure. The beta-derivative's diagnostic value was compared to that of the Bourdet Derivative and the Primary Derivative The β-derivative has significant diagnostic value for identifying power-law type of flow regimes (such as wellbore storage, linear flow, bilinear flow, boundary-dominated flow, etc) because it possesses a recognizable unique character for each of these flow regimes. For instance, the β-derivative is 0.5 for linear flow, 0.25 for bilinear flow and 1.0 for boundary dominated flow. In addition, since the β-derivative is dimensionless, it can be used to differentiate the performance of wells producing from the same field or from different resource plays. The new plotting functions presented in this paper are not intended to replace existing diagnostic functions but can be used in conjunction with them to enhance production data analysis.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition, October 17–19, 2017

Paper Number: SPE-186238-MS

..." will be tested. The

**beta**ratio used in the testing are 0.45 and 0.75. The testing goals regarding the coefficient of discharge (Cd)**curve**performance doing in standard test and non standard test. In standard testing, each size of DP Cone meter connected with straight pipeline with 36D upstream length and 19D...
Abstract

Demanding of oil & gas more increasing every year. However domestic production in Indonesia could not cover the demand, this phenomena resulting the deficit of oil & gas domestic stocks. Therefore, searching the new oil & gas sources shifting from onshore to the offshore and also deep water. FPSO development become the one important things to support exploration activities. One of the obstacles when design the production facilities in FPSO is limitation of space. All process equipment and instrument must be suitable with vessel space. Almost process instrument mainly in flow meter require upstream and downstream length to guarantee the accuracy of measurements. In this paper will discuss about DP cone meter performance in support metering system in FPSO facilities. DP cone with size 2" and 6" will be tested. The beta ratio used in the testing are 0.45 and 0.75. The testing goals regarding the coefficient of discharge (Cd) curve performance doing in standard test and non standard test. In standard testing, each size of DP Cone meter connected with straight pipeline with 36D upstream length and 19D downstream length without flow disturbance element pipeline. Dp cone meter with size 2" tested with fluid which has Reynolds number 18,000 to 152,000 Re, and also Dp cone with size 6" tested with fluid which has Reynolds number 61,800 to 715,000 Re. In non standard testing, Dp cone meter directs connected with out of plane 90 degree elbow without requirement installation length in upstream and downstream and half of moon orifice plate with 3D upstream length and 5D downstream length. Maximum fluid Reynold number in the testing are 148,000 to 556,000 Re. The results of testing showing that coefficient of discharge (Cd) Dp cone in standard testing and non standard testing do not change significantly. The curve showing good linearity and good performance. It verifies that Dp cone meter has resistance to swirl effect and poor flow profile. So, this flow meter more suitable with limitation space installation as FPSO

Proceedings Papers

Ezinne Amanda Nnebocha, Akinola Akinbola, Omagbemi George Kakayor, Adetayo Odutayo, Tunji Olukayode, Olawale Oguntayo, Chukwuma Onwuchekwa, Ashutosh Dikshit, Akanimoh Bassey Nkanga, Temitope Ilusemeti, Amrendra Kumar, Aleksander Rudic, Oluwatoyin Samuel Olagunju, Richmond Nduka Nwaokwu, Chidi Henry Ugboaja

Publisher: Offshore Technology Conference

Paper presented at the Offshore Technology Conference, August 16–19, 2021

Paper Number: OTC-31301-MS

.... Production forecast shows incremental oil recovery from using AICDs in

**Beta**-7 to 5%, and 17% in**Beta**-8. Figure 16 Comparison of**Beta**-7 flow profile (left), and production forecast (right) with AICD (brown**curve**) and without AICD (red**curve**). Figure 17 Comparison of**Beta**-8 inflow profile...
Abstract

Discovered in 1964, the Beta Field in the Niger Delta sedimentary basin consists of 25 stacked hydrocarbon-bearing reservoirs located between 5,500 and 12,000 feet true vertical depth subsea (TVDSS). A total of 26 wells have been drilled in the field, of which 11 are presently on production. Oil production peaked at 8,900 stock-tank barrels per day shortly after field start-up and has been on the decline. More than 40 years since production start-up, the Beta Field remains a relatively immature, distinctly underdeveloped asset. Only about 59 million stock tank barrel (STB), or 8% of its estimated stock-tank oil initially in place of 740 million STB, had been produced by the end of 2017. Two horizontal wells were planned in the field to provide additional drainage points and increase field production. However, a production forecast of the planned wells showed potential early water breakthrough and high water cut because of unfavorable mobility ratios of a slightly viscous oil and proximity to oil/water contact (OWC). To mitigate the production challenges and improve the reservoir sweep, autonomous inflow control devices (AICDs) were selected to be installed on the sandface completion. These wells were drilled and completed during the COVID-19 pandemic, bringing additional challenges in equipment availability and logistics with potential to derail the successful completion of these wells within the required timeline. An innovative retrofit screen design, leveraging detailed engineering design and remote collaboration, enabled the conversion of ICD sand control screens to cyclonic AICD screens. AICD nozzle placement was optimized using a reservoir-centric workflow that integrates the full reservoir model with the sandface completion. Real-time interpretation of the data enabled computation of porosity-permeability and saturation estimates from logging-while-drilling (LWD) logs, which was then used in updating the reservoir model in near-real time. Using a segmented well modeling approach and a refined flow distribution from heel to toe, AICD nozzle placement was optimized in real time utilizing LWD measurements from open hole along the horizontal drain, aiding the design and configuration of the AICDs. The Beta-7 and Beta-8 wells were successfully drilled, completed, and put on production. The horizontal drains were landed within 5 to 10 feet of the top of the reservoir, maintaining at least 20-ft distance from the OWC. The forecasted simulation showed possible water influx from the toe of the horizontal as opposed to the heel because of existing water leg and high permeability at the toe. This was supported by high water-cut production from that zone in the nearby wells. This insight from the full-field simulation model enabled an informed decision on the AICD design.

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