Riopipeline2011 1391 Artigo Rio Pipeline Corrigido. 1

7/27/2019 Riopipeline2011 1391 Artigo Rio Pipeline Corrigido. 1

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______________________________1M.Sc. Student in Petroleum Engineering DPET/UFRN2Ph.D., Chemical Engineer DPET/UFRN3Ph.D., Chemical Engineer DCTM/UFBA

IBP1391_11OPTIMIZATION OF THE OIL AND GAS FLOW IN MATURE

FIELDS

Jlio C. S. Nascimento1, Lindemberg J. N. Duarte2, Luiz C. L. Santos3

Copyright 2011, Brazilian Petroleum, Gas and Biofuels Institute - IBPThis Technical Paper was prepared for presentation at the Rio Pipeline Conference & Exposition 2011, held between September,20-22, 2011, in Rio de Janeiro. This Technical Paper was selected for presentation by the Technical Committee of the event. Thematerial as it is presented, does not necessarily represent Brazilian Petroleum, Gas and Biofuels Institute opinion or that of itsMembers or Representatives. Authors consent to the publication of this Technical Paper in the Rio Pipeline Conference &Exposition 2011.

Abstract

Technologies capable of predicting the behavior of multiphase flow in oil and gas pipelines have been

developed dramatically over the past 60 years. With them, it is possible to determine the pipe diameter, pressure drop,flow patterns, among others. In the petroleum industry, it appears that the maturity of a field causes significantinfluences on the flow regime during the production phase. Such flows may occur within the reservoir, productioncolumns, rows of upwelling, risers and transfer lines for refining units. The correct understanding of how the biphasicmixture behaves during the flow in each production component is of fundamental importance to dimension productionsystems able to produce with maximum efficiency. Therefore, the aim of this work is the optimization of oil and gas

production in the 1-FMO-001-BA well, belonging to the Field-School Project (ANP / UFBA), located in the ReconcavoBaiano, Entre Rios. In this context, new and improved flow conditions have been studied which will help with someurgency to expedite the process of control, diagnosis and decision making to maximize its production. The biphasicmixture is transported from the wellbore to the wellhead through the production column with an inner diameter of 0.051meters and 3375 meters of length. Then the fluids are directed to a separator vessel through a production line of 0.076meters of inner diameter and 37.34 meters of length. The oil and gas flow rate recorded just after the separator is 6.9 mstd/d and 6400 m std/d, respectively. It is also known that the pressure in the head remains stable at 51.89 kgf/cm. The

study was modeled by numerical simulation of multiphase flow in pipelines for various operating conditions of the well,such as the effects of the diameter variation and the gas-oil ratio (GOR). From the flow conditions simulated in the

production column, it was observed that the pressure gradient decreased significantly with increasing GOR. This may becaused by the reduction of the mixture density due to the increase in the quantity of gas. By analyzing the diameter ofthe production column, it was observed a reduction on the pressure gradient for diameters lower than 0.051 meterswhich might be due to the friction reduction between the fluids and piping. On the other hand, for larger diameters, itwas noticed an increase in the gradient pressure due to the increase of the hydrostatic column. On the production line thevariation of these parameters showed no significant effect, so that the pressure drop observed between the wellhead andthe separator vessel was practically nil.

1. Introduction

Petroleum has a key role in the existence of humanity being the main feedstock for energy production. Thesearch for more efficient systems for oil production has been continuous over recent years.

The production involves the oil extraction from the reservoir to the surface. In the reservoir, the oil is undercertain conditions of pressure and temperature, which determine an equilibrium state. During production, this balance is

broken and the fluid may take a wide variety of behaviors.For Gilbert (1954), three distinct flow categories can be observed on an oil production system, as follows: flow

on the reservoir, flow on vertical tubing and surface flow. Figure 1 shows the production stages of natural lift Wells. Forthe fluid reaches the surface and be produced in the desired flow it is necessary that the load losses imposed by the threestages of flow are overcome.


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Figura 1. Production stages of natural lift Wells

From Figure 1, it is expected that the dissolved gas will be released from the oil due to its depressurization,resulting in a multiphase flow (oil, water and gas). The concept of phase and component can not be distinguished fromthis type of flow, but the number of interfaces present in the flow. For example, two-phase flow means the presence ofan interface; it can be either liquid-liquid immiscible (oil and water) or liquid-gas (oil and gas). For the case ofmultiphase flow, it has the presence of two interfaces, liquid-liquid-gas (water, oil and gas), though the mixture is

biphasic (OLIVEIRA, 2003).It is very important to understand how the gas-liquid mixture behaves during the flow on each stage in order to

scale production systems able to produce with maximum efficiency. In Petroleum Engineering, the design of production

facilities is often done through what it is called by Nodal Analysis. From that, the production of oil and gas in aparticular well is evaluated and so the effects of various components, including: tubing diameter, pressure drop, flowpatterns, among others. Each component is evaluated separately and the entire system is combined to optimize the floweffectively (NASCIMENTO, 2011).

2. Background and Purpose

In Brazil, the oil industry emerged in the 30s with the discovery of oil and gas deposits in the Recncavo Basin.Since then, the national industry has evolved into new discoveries in nearly the whole country, reaching self-sufficiencyin production through the exploration of offshore deposits which comprise about 84% of national production. The oilfields on the Reconcavo Basin has been producing over 30 to 60 years with advanced stages of exploitation. As a result,

they present a declining production close to their economic limits. These fields are often called Mature Fields and,although less profitable than they were in the past, they have great economic importance for the regions near to theirlocations, either by heating the local market, gathering royalties, or by attracting local skilled workers (CMARA,2004).

In this sense, the aim of this work is to study the optimization of the flow of oil and gas on the mature field ofFazenda Mamoeiro, which is operated by Well 01-FMO-001-BA. Therefore, the intention is to identify new andimproved flow conditions that contribute urgently to expedite the process control, diagnosis and decision making tomaximize their production.

3. Multiphase Flow in Pipes

Models able to predicting the behavior of multiphase flow in pipelines have been developed extensively overthe past decades.With them it became possible to predict tubing diameter, pressure drop, flow patterns and separator

pressure (BRILL and MUKHERJEE, 1999).


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Brill and Arirachankaran (199a) The Empirical Perio

During this period several authfields and laboratory tests. The parame

properties, diameter, orientation, rougmultiphase flow is considered homogen

b) The Awakenig YearThe empirical correlations us

computer in the early 1980s, becamepipes can be better understood by meconcept of Nodal Analysis, able to measystem.

c) The Modeling PerioMechanistic models were de

multiphase flow can be characterized b

3.1 Pressure Gradient

The pressure gradient in pip

combination of the laws of conservation

It is observed that the total preacceleration. The pressure gradient due

proportional to the specific gravity thvertical tubing. The friction part referscontributes with about 5-20% of lossesrate. At last, the acceleration componenhigh water content and low gas-liquid r

Figure 2 shows the finite contr

For the case presented on Figucan be calculated by Equation 2.

Where, mis the mixture densi

average speed of the mixture and d is th

Rio Pipelin

) divided the development of such models in three disd (1950 a 1975)

ors have developed empirical correlations from obserers used to build these correlations include: oil and gness and pipe pressure, flow patterns and liquid h

eous, i.e. it is assumed that oil and gas flow with the s(1970 a 1985)

d to predict pressure gradient, coupled with the ina practical tool available to petroleum engineers. T

ns of numerical integration techniques. Brown et al.ure and evaluate the production performance from a

(1980 Present)

eloped from the restrictions imposed by empiriccreating physical models based on physical and phen

s can be calculated by Equation 1. This equatio

of mass and momentum.

ssure gradient is a consequence of the sum of three p the elevation corresponds to the weight of hydrostat e produced fluids. It represents 80-95 % of the tot

to the losses caused by the contact between the fluid. Furthermore, friction losses may vary with pipe dit refers to losses caused by the velocity variation insi

tio, the gradient due to acceleration can be considere

l volume in pipes.

Figure 2. Finite control volume in pipes

e 2 and assuming a homogeneous gas-liquid mixture,

ty; ftpis the two-phase friction factor and depends on

e pipe diameter. For vertical flow, =90, sin90=1 an

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tinct periods:

ations of actual data of oilas flow rate, physical fluidoldup. In some cases, theme velocity.

troduction of the personale pressure behavior along(1984) presented the truearticular component in the

l correlations. From that,omenological principles.

was originated from the

(1)

arts: elevation, friction andc column and it is directlyl pressure gradient in thewith the pipe walls and it

meter, roughness and flowe the pipes. For flows withnull (THOMAS, 2001).

the total pressure gradient

(2)

the method used; vmis the

d dL=dZ.


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4. Methodology

The work was conducted on the 01-FMO-001-BA well, located at the Reconcavo basin, which is operated byField-School Project (PCE) in partnership with the Brazilian National Agency of Petroleum, Natural Gas and Biofuels(ANP). The gas-liquid mixture leaves the reservoir and flows to the surface through a vertical tubing of 3375 m of

length and 0.051 m of inner diameter. After reaches the wellhead, the fluids are directed to a primary petroleumprocessing plant through a flow line with 0.076 m of inner diameter and 37.3 m of length. The flow line has threedistinct sections, the first one (vertical) that comes from the choke to a horizontal pipe in the subsurface (second section)and then another vertical one that connects to the separator vessel. In the last section there is a safety valve SDV (shut-down-valve) installed for automatic shutdown in case of some uncontrolled flow from the well.

In this work, the pressure gradient was predicted by Beggs and Brill (1973) correlation. This correlation canaccurately describe the multiphase flow behavior for all flow patterns and pipes inclinations. In addition, a blackoilmodel was used to determine the fluid properties. Numerical simulations were performed by using the DPDL computer

program developed by Shoham (2005). The aim is to evaluate the oil and gas flow performance on the vertical andhorizontal tubing by changing its diameter and gas-oil ratio.

By setting the inlet pressure at the separator vessel to 0.483 MPa and leaving the choke fully opened, it couldbe observed an oil production of 6.9 m std /day with a gas-oil ratio of 927.54 m std / m std. These were the initialvalues used on the simulations.

5. Results and Discussion

5.1 Vertical Gas-Liquid Flow

Figure 3 shows the pressure gradient in the vertical pipe versus depth, calculated by using Equation 2.

(

(

Figure 3. Vertical flow pressure gradient

It can be observed from Figure 3 that the pressure varies continuously with depth in a nonlinear way. Thisbehavior occurs due to the gradual release of gas from the oil as there is pressure loss in the column. The flowing bottomhole pressure (Pwf) observed in front of perforations is about 10.8 MPa.

The tubing diameter and gas-oil ratio effects on the column pressure gradient are shown on Figures 4 and 5,respectively.


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(

(

Figure 4. Tubing diameter effects on the vertical pressure gradient

According to Figure 4, the Pwfranged from 7.6 MPa to 19.4 MPa by varying the tubing diameter from 0.0381m to 0.127 m, respectively. It is expected that increasing the tubing diameter results in a reduction of the pressure dropdue to the reduction of liquid and gas superficial velocities, which also reduces the friction loss. On the other side, byincreasing the tubing diameter also favors an increase in the pressure drop due to the elevation losses. This is explained

by the fact that higher diameter corresponds to a higher cross-section area which results in a higher Pwf.From Figure 4 it can be observed that the Pwffor the tubing diameter 0.031 m and 0.0508 m is smaller than that

of tubing diameter of 0.0254 m. For these cases, the increase of tubing diameter resulted in a decrease of the pressuredrop by friction loss. For tubing diameters higher than 0.0635 m, the friction loss was not so important. However, itcould be noticed an increase of Pwfand consequently an increase of the pressure drop due to elevation losses.

On the oil industry, the choice of the optimal tubing diameter depends on several factors. However, the bestchoice is one that provides the lowest possible cost along with lower pressure loss and the best flow pattern for the

production systems. Applying the first two parameters as a criterion for determining the diameter of the vertical tubing

operation, it came to a conclusion that the 0.0381 m diameter offers the lowest pressure drop with the lower materialcosts for manufacturing.

Figure 5 shows the influence of the GOR in the pressure gradient on the vertical tubing.

(

(

Figure 5. Effect of GOR on vertical tubing pressure gradient

It can be observed from Figure 5 that increasing the GOR from 178 m std/m std to 1780 m std/m std wouldcause a decrease on the flowing bottom hole pressure (P wf). For a GOR of 178 m std/m std and an oil flow rate of 6.9

m std/d it is necessary a Pwf nearly of 20 MPa. The minimum Pwf is observed when working with the maximumsimulated GOR of 1780 m std/m std.


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It is expected that the increase of the GOR on the vertical tubing helps to reduce the density of the multiphasemixture, thus favoring the reduction of pressure drop by reducing the elevation loss. However, the progressive increaseof the GOR reaches a point where the pressure gradient stabilizes and begins to grow. This is a result of the increasedfriction and acceleration losses which is higher than the effect of the hydrostatic column density.

These changes on the behavior were not observed on the GOR simulated on this work. Thus, there are twopossibilities for choosing the best GOR on the vertical tubing. The first one is working with the lower Pwf whichimplicates that the reservoir is feeding the well near to the maximum production capacity. The second possibility isoperating the well with the lowest GOR. Since the driving mechanism is gas in solution, by keeping the lowest GORhelps to maintain the production energy inside of the reservoir which leads to a longer production time by natural lift.

5.2 Horizontal Gas-Liquid Flow

The same methodology used on the vertical gas-liquid flow will be applied to analyze the horizontal gas-liquidflow. The flow line pressures were determined by adding up the pressure drop from the separator to the choke with theinlet pressure of the separator.

Figure 6 show the pressure gradient against length.

(

(

Figure 6. Horizontal flowing pressure gradient

It can be observed from Figure 6 that there was almost no variation on the pressure drop between the separatorand the wellhead. This might be due to the low oil flow rate and small tubing length which are not sufficient to causelosses on the overall system.

The tubing diameter and gas-oil ratio effects on the horizontal pressure gradient are shown on Figures 7 and 8,respectively.

(

(

Figure 7. Tubing diameter effects on the horizontal pressure gradient


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It can be seen from Figure 7 a reduction of the pressure drop in the flow line due to the increase of the pipediameter. This is explained by the decrease on the liquid and gas superficial velocity, which reduces the friction andacceleration losses. For tubing diameter of 0.0254 m the pressure on wellhead is approximately 0.8 MPa. By increasingthe tubing diameter to 0.0381 m, the pressure on the wellhead decreased significantly to 0.51 MPa. For tubing diametershigher than 0.0508 m, no significant variation could be observed on the pressure drop. This leads to a conclusion thatthe wellhead pressure tends to decrease with the increase on tubing diameter, reaching the limit where thereafter theincrease on the diameter does not contribute for the reduction of the friction loss and therefore the pressure remainsconstant at the wellhead.

The gas-oil ratio effect on the flow line pressure drop is shown on Figure 8.

(

(

Figure 8. Effect of GOR on horizontal flow line pressure gradient

In general, it is expected that an increase on the gas-oil ratio in horizontal pipes cause an increase on thepressure drop. This is expected due to the increase in the gas superficial velocity, which results in an increase of the

acceleration and friction losses leading to an increase in the total pressure gradient.From Figure 8 it could be noted that the GOR values simulated in this work caused no variation on the pressuredrop on the flow line. Thus, the best GOR will be defined based on the results of the vertical tubing and also on thelogistics and the operational conditions for the production and sale of the oil and gas on this well.

6. Conclusions

The following conclusions were obtained by evaluating the pressure gradient in the vertical tubing andhorizontal flow line with respect to tubing diameter and GOR:

1. The vertical flowing pressure gradient varied continuously with depth in a nonlinear way. By keeping thewellhead pressure at 0.48 MPa, the flowing bottom hole pressure obtained was approximately 10.8 MPa;

2. The pressure drop reduction caused by the increase of the vertical tubing diameter was only observed fordiameters below 0.0508 m. For tubing diameters higher than 0.0635 m, it was observed an increase of the

bottom pressure due to an increase of the elevation loss;3. The progressive increase of the GOR on the vertical tubing contributed solely to decrease the pressure gradient;4. For the conditions simulated on the flow line, no significant pressure loss was observed between the separator

and the wellhead. A good consistency was observed by analyzing the effects on the piping diameter and GOR.A significant pressure drop was only observed for diameters lower than 0.0508 m. Regarding to GOR, it wasalso observed no influence on the pressure gradient;

5. From these analyses it can be concluded that the optimization of oil and gas flow in Fazenda Mamoeiro Fieldwill be achieved if it operates with a vertical tubing diameter of 0.0381m and a horizontal flow line diameter of0.0508 m. By taking into account the evaluation of the pressure gradient on the vertical tubing and horizontalflow line it can be concluded that the best GOR will depend on the logistics and operational conditions for the

production and sale of the fluids.


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7. Acknowledgements

The authors would like to acknowledge the collaboration of the Field-School Project (UFBA/ANP) forproviding the operational data for the 01-FMO-001-BA Well.

8. References

BEGGS, H. D., BRILL, J. P. A Study of Two-Phase Flow in Inclined Pipes. Journal of Petroleum Technology, p.607-617, 1973.

BRILL, J. P., MUKHERJEE, H. Multiphase Flow in Wells. Texas: Society of Petroleum Engineers Inc, p. 149,1999.BRILL, J.P., ARIRACHAKARAN, S.J. State of The Art in Multiphase Flow. In: BRILL, J. P.; MUKHERJEE, H.

Multiphase Flow in Wells. Texas: Society of Petroleum Engineers Inc, p. 149,1999.CMARA, R. J. B. Campos Maduros e Campos Marginais: Definies para Efeitos Regulatrios. Master's dissertation.

UNIFACS, Salvador, p. 139, 2004.GILBERT, W. E. Flowing and Gas-Lift Well Performance.Drilling and Production Pratice, p. 143, API, 1954.

NASCIMENTO, J. C. S. Otimizao de Escoamento Multifsico: Um estudo no Poo 1-FMO-001-BA. Graduationconclusion work. UFBA, Salvador, p. 91, 2011.

OLIVEIRA, M. F. D. Anlise da Aplicao de um Sistema de Bombeamento Multifsico Submarino na Produo dePetrleo. Master's dissertation. PUC-RJ, Rio de Janeiro, 2003.

SHOHAM, O. DPDL Multiphase Flow Pressure Loss Computer Code. In: TANAN, U. L. P; DUARTE, L. J. N;NASCIMENTO, J. C. S; GIS, L. N. Caracterizao dos Padres de Escoamento Para o Fluxo Multifsico dePetrleo em Campos Maduros.RioOil & Gas Expo and Conference, Rio de Janeiro, 2010.

THOMAS, J. E. Fundamentos de Engenharia de Petrleo.Rio de Janeiro: PETROBRAS, Intercincia, 2ndEd., p. 267,2001.

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Riopipeline2011 1391 Artigo Rio Pipeline Corrigido. 1