Production Enhancement of a Brown Field in the Niger Delta Using Well Intervention Techniques

Production Enhancement of a Brown Field in the Niger Delta Using Well Intervention Techniques

Dulu Appap, Okoro Ejike3

2,3Petroleum Technology Development Fund Gas Research Group,

University of Port Harcourt, Port Harcourt, Nigeria

Agada Ugbedeojo1,

1Centre for Petroleum Geosciences, School of Graduate Studies, University of Port Harcourt,

Port Harcourt, Nigeria.

Abstract- OB oil field in the Niger Delta is not producing optimally because of decline in reservoir pressure and low recovery efficiency. The wells have been producing for over 50 years, so the equipments are faulty resulting in premature well abandonment. This work diagnosed the problem of the field, developed a systematic method of production enhancement, and modeled the reservoir, using eclipse 100 to perform multiple sensitivities on some variables to identity conditions for optimum production, and enhance the productivity of the well. The result shows that the mobility ratio of the field is 0.5 therefore water flooding is the best choice for increasing the pressure, also the maximum number of wells required is two production and three injection wells. The distance between injectors and producers is 9110ft. From the design short radius horizontal wells yielded optimum recovery but are discarded because of poor economic viability, hence vertical wells are the best choice for optimal production.

Keywords: Brown field, Production enhancement, Simulation, Eclipse and Well Reservoir Management, Water Flooding

Symbols and Annotations

CCT Coiled Tubing Technology DD Directional Drilling

Bbl Barrels

GF Giant Field

OWC Oil Water Contact

HCIIP Hydrocarbon Initially in Place M Mobility Ratio

MOV Movable Oil Volume

Krw Relative Permeability of Water Kro Relative Viscosity of Oil

dp Increase in Pressure

dl Increase in Length

A Area

q Oil flow rate

k Permeability

µ Viscosity

µ0 Oil Viscosity

µw Viscosity of water

1. INTRODUCTION

Oil companies are experiencing dwindling oil reserve, and the discovery of new oil field is becoming more difficult. For these reasons, both co-operate and private individuals are channeling their interest and resources to enhance

production from existing field and optimize mature fields to remain in business.

Principles, and cost reduction measures and utilization of latest technologies are the key to maximizing economic recovery from matured reservoirs [1], [11].

In the early phase of many crude-bearing sands, oil production is prolific, the primary principal expenditure focus on the external part. As a result reservoirs that are not producing much are quickly abandoned for fields that are more productive. High rewards lie in the world of brown fields. The world average recovery factor is between 35%

– 37%, which implies that about 63% – 65% reserves still remain untapped.

As a result of new technologies deployed in improving matured field, the worlds crude oil condensate reserves increased from 1.654 trillion to 1.656 trillion bbl at year end 2015. Total gas reserves jumped from 30.7 cu ft to

6.95 quadrillion cu ft [2]. About 30 giant fields make up 50 percent of the worlds oil reserves and most of them are classified as matured fields. Novel and techniques that is economically viable and sound reservoir management strategies are prerequisite for the development of mature fields.

The technologies to restore brown fields are based on either reservoir or well applications. The determination of the optimum number of wells that can deplete the well is key to the enhancement of brown fields, once it is achieved well development practices like recompletion, stimulation, treatments, optimization of lift, surveillance, new entries and recollection of data are considered, followed by drilling of injectors for pressure maintenance or displacement [3].

A matured field is one that has been producing crude oil for a long time and is experiencing low production rate, low recovery efficiency, premature well abandonment, high volume of produced water and decline in reservoir pressure. In Nigeria since the first discovery of crude oil in commercial quantity in Oloibiri, Bayelsa State in 1956, more oil fields had been discovered apparently reservoirs that had been producing for a long duration are experiencing decline in oil production because of reduction in reservoir pressure. Hence it is pertinent to consider

revamping brown fields in Nigeria to recover reasonable crude oil from these reserves to increase the economic fortunes of the country [12].

2 ENHANCING PRODUCTION IN A BROWN FIELD About 70% of world oil production is from developed oil fields which has being in production for more than 30 years [4]. In some field well mediation are performed to improve oil production rate.

In Oman North field, well mediation project was undertaken in the year 2003 to 2005, which increased the field oil production rate [1]. The activities performed in the field to improve its productivity are outlined below:

1. Well surveillance: Different logs were run, pressure integrity tests for wells and reservoirs were also taken, coiled tubing and wire line units were deployed to determine where, when, and how to mediate.

2. Respectability exercise were undertaken to restore the wells to standard working conditions, which include: tubing patches, and squeeze.

3. Reclamation exercises were carried out to increase the field oil production rate; these include substitution of electrical submersible pumps, Gas lift valves and recapture of blocked holes.

Coiled tubing technology(CTT) has being in use for well maintenance and remedial work since 1960s, CTT is a continuous length of pipe that is stored , wrapped around a large reel, the same way a thick electrical cable is stored and shipped. The low cost and reduced environmental impacts of CTT have contributed to this growth. Directional Drilling (DD) of wells with horizontal distance of over 1,500 feet has been accomplished using coiled tubing. Drill out of blockages in existing wells using positive displacement mud motors mounted to Coiled tubing without the prior removal of production tubing or liners [5],[6]. Coiled tubing is also used in the traditional work over application, as well as in horizontal wells to insert and manipulate flow control equipment that regulates reservoir drainage [7].

DD was applied to increase the recovery factor of fluid dominated deltaic sandstone reservoir characterized by low permeability and underlain by a sandstone aquifer in Pennsylvanian Bartlesville sand.

In the Flatrock Field of Osage County, Oklahoma, the field produced over 30 million barrels of oil with over 1,000 conventional wells. Explosives were used to fracture the old vertical wells used which resulted to increased initial oil production rates to economic levels. However they also developed increased water cut immediately they clocked 12 months of service. To remedy the situation a horizontal

well was drilled at a horizontal distance of 1,050 feet. Though oil production rate was not increased, the water cut was reduced from 75 percent to 14 percent [8].

In New Hope Field, Franklin County, Texas, dramatic increase in oil production rate was recorded by Texaco Exploration and Production Inco., when they drilled two horizontal injection wells into the reservoir. The injection wells were placed about 8,000 feet deep lower on the anticline structure of the field than the existing producing wells. This resulted to increasedproduction per producing wells from 100 to 400bl/day, the highest production rate in the history of the field [9].

In Grassy Creek Trail Field, Emery and Carbon Counties, Utah, discovered in 1953 with five vertical wells which produced about 141,000 barrels of oil in 1961 and 1976. A second development program started in 1982 with the application of multiple short lateral borehole completions. Sixteen wells were drilled, but thirteen delivered production of 358,817 barrels of oil in a period of six years, two and half times the amount delivered by the five conventional wells during sixteen years [10].

1. RESERVOIR MODELING AND SIMULATION Eclipse test was used to simulate the well, perform various affectability examinations to the ideal condition of the well for optimum performance.

   1. Simulation workflow

      The following steps were taken to build the repository model.

      1. Analysis of the geographical rock and liquid properties of the depository.

      2. Estimation of the oil in place.

      3. Using the outcomes from step 1 and 2 to build a three dimensional depository model.

      4. History matching of the wells

      5. Using the developed reservoir model to test and observe the repositorys reaction to changes in choice variables. This enables the determination of the ideal conditions that will improve the efficiency of the well.

   2. Model description

   A critical aspect of the reservoir reproduction is to isolate the waste range of the supply into various cells. The cells are characterized in the x, y, and z bearings as shown in Figure 1. A total of 212 and 91 cells were characterized in I and J bearings respectively. The thickness of the matrix is characterized with 64 layers in 2 bearing. The model comprises of 212, 212 matrix cells with measurements of 327ft x 322ft x 7ft. The oil in place is 162mm barrels.

   Table 3.1: Reservoir Properties

   Figure 3.1: Showing Grid Dimension

   Average NTG	Reservoir B1 = 0.4
   	Reservoir B3 = 0.7
   Average Porosity	B1= 0.18, B3 = 0.19
   Initial water saturation	0.3
   Oil API	370
   Oil Viscosity	0.68cp 1.08cp
   Boil/rb	1.3scf/stb
   Initial Pressure	4066 psia
   Oil Water Contact	B1 = 9305 ft
   	B3 = 9377ft
   Dip Angle	0.4 deg
   Average Pressure	4110 psia
   Average Permeability	238 mD
   Reservoir Temperature	175 0F
   Water Viscosity	0.36 cp
   Initial GOR	650- 750 Scf/stb
   Bubble Point Pressure	3820 3920 Psi
   Gas Oil Contact	9089 9134
   HCIIP	162 mmbls

   1. Well Count

2. RESULTS

   To determine the ideal number of wells that can deplete the reservoir, a creaming bend was developed. This is essentially a plot of aggregate oil production against aggregate of delivering wells. The creaming bend shows the point at which lessening return happens for a specific number of wells.

   The creaming bend for the field (Appendix 1) was produced by plotting one vertical production well after another in various areas in the repository model. The number of wells before the smoothed zone is chosen as the number to initiate production. The bend smoothed when the number of wells is 5. This implies that the number of wells required to deplete the field will not exceed five.

   The well positioning process, initiated with 5 vertical production wells and four infusion wells for pressure upkeep and oil dislodging towards the well bores.

   Figure 4.1: Pressure Depletion over Time

   The production wells were set utilizing the systems

   =

   4.1

   specified. They were made to cut crosswise over layers that have recoverable measure of oil. Wells were allotted with a steady rate of 6,000bb/day at a bottom-hole press of 2500psi. The outcomes from every run were broken down and well with high water cuts and low production rates

   This condition of low viscosity has similar result as high permeability in stimulating high flow rates thus fast- tracking field improvement by combining the end point relative permeability and by application of Darcys law:

   were disposed. The quantity of injection wells was reduced for every well killed and production rate of the remaining

   = max.Vel.of the displacing phase (water) Max.Vel.Of the displaced phase (oil)

   4.2

   wells was increased. The procedure was repeated for four, three, two and one vertical well separately. The ideal number of wells that yielded optimum oil recovery rate is two vertical production and 3 infusion wells as shown in Appendix 1.

   1. Recovery Mechanism for the Development Scheme From table 3.1, the air point pressure of the field is constrained close to the reservoir pressure, as production is initiated, the slight distinction in the supply and air pocket point pressure results in the freedom of gas, as the pressure falls below the pocked point pressure. This leads to a rapid drop in pressure with time (Figure 4.1). The precarious pressure drop is undesirable because a low repository pressure implies a decrease in oil production rate. Hence, an auxiliary strategy for oil recovery is required to compensate for the quick decrease in pressure.

   2. Choice of Pressure Maintenance

      The choice to conduct water flooding in oil fields is customarily considered when the oil viscosity is low, so that the mobility ratio is less than unity, from Darcys law:

      By substituting the parameters of table 1, the mobility ratio (M) = 0.5.

      This implies that the oil will travel faster than the water, hence dislodges it in a perfect piston like fashion. This is the most satisfactory form of displacement and denotes that the total volume of moveable oil can be recovered by injection of a corresponding volume of water; consequently the flooding is correspondingly proficient and speedy. Hence water flooding is the best choice for pressure upkeep.

   3. Optimal Well placement

      The strategy employed for situating wells was distinguishing the sweet spots in the supply which yields the highest oil rate. Sweet spots are districts where crude oil is situated in the reservoir.

      The second strategy was to position wells on the up plunge (far from the oil water contact (OWC)) of the

      repository, to forestall water coning as shown in Figure 4.2.

      Figure 4.2: Wells Positioned on th.e up plunge

      Figure 4: Optimum Well Placement

   4. Improvement of Volumetric Sweep Efficiency

   The injection and production wells were re-aligned to increase the total reservoir volume that is swept by the injected fluid which resulted to increase in volumetric sweep efficiency.

   Distance (ft)	Field displacement efficiency (%)	Cumulative Oil Production
   3,000	38	55.985664
   5600	40.9	66.396452
   9110	43	70.823232

   Table 4.1: Injector Well Distance Sweep Efficiency

   • Water flooding was employed to maintain the reservoir pressure because of the fields low mobility ratio of 0.5.

     ACKNOWLODGMENT

     The authors wish to show their appreciation to Petroleum Technology Development Fund Ga Research Group, University of Port and Centre for Petroleum Geosciences, University of Port for their absolute support for this research work.

     1. Determination of Optimal distance between injectors and Producers

        From Figure 3, producer IBEDEZ and IBEDE4 yielded the highest oil rate. IBEDE4 has the highest water cut as a result of the closeness of injector 2 to IBEDE4. The wells were repositioned and injectors placed beneath the oil OWC to expand water drive to both makers.

        From table 4.1, the highest field displacement efficiency yielded the highest cumulative oil production; hence the injectors were placed at a distance of 911ft from the producers.

3. CONCLUSION

To improve oil production in a brown field with a solution gas drive. Eclipse 100 black oil simulation was used to determine the conditions for optimum oil recovery. The field model with water injectors was developed.

• Short Radius Horizontal wells gave the highest recovery, but were replaced with vertical wells because the drilling expenses were not absorbed by the income generated.

• From the design two production and three injection wells yielded optimum oil production rate.

• The optimum distance between injectors and producers is 9110 ft

REFERENCES

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1. and Al-Sairni, M (2006). Enhancing Production from Mature Field by Focusing on Well Intervention Management. Journal of Society of Petroleum Engineers 99706.

[2]. Conglin Xu, Tayvis Dunahoe, Micheal T. Slocum and Laura Bell (2015) Reserves Grow Modestly as Crude Oil Production Climbs

Oil and Gas Journal, USA

[3]. Babadagli T (2007) Enhancement of Mature Oil Fields Journal of Petroleum Science and Engineering.

[4]. Wengrong, X. (2007) Tapping Potentials of Mature Oil Field. Technology application in Chinas Eastern Oil fields. Houston Texas.

[5]. Alexander Sas-Jawarsky, (1991), Coiled Tubing Operation and services, Part 1- The Evolution of Coiled tubing equipment, World Oil, Washington DC, USA.

[6]. M Wasson, F. Pittard and L. Robb, (1991), Horizontal Work over with Coiled Tubing and Mot ors Petroleum Engineers International, Washington DC, USA.

[7]. Cameroon White and Mark Hopman (1991), Controlling Flow in Horizontal Wells. Word Oil, November 1991. Washington DC, USA.

[8]. John E. Rougeot and Kurt A. Lauterbach, (1991 The Driller of a Horizontal Well in a Matured Field. Washington DC, USA.

[9]. Horizontal Wells Inject New Life into Mature Field Petroleum Engineer International, April 1992. Washington DC, USA.

[10]. Gary C. Mitchell, Fred E. Rugg and John C. Byers (1989), The Moenkopi: Horizontal Drilling Objective in East Central Utah Oil and Gas Journal. Washington DC, USA.

[11]. Zona N. Antariksa, Dian Ultra, Aldani Malan and Tejo Sukotrihadiyono [2015] Reviving Brown Field Oil Potential: Case Study of Multilayer Reservoir International Petroleum Conference. Malaysia.

[12]. Anelse Q. Lara et al (2011). Petrobras Eperience on Water Management for Brown Fields. Offshore Technology Conference. Houston, Texas, USA.

APPENDIX

Appendix 1: Creaming Curve