Hydrocarbon and Non-Hydrocarbon WAG Processes ...

Modern Environmental Science and Engineering (ISSN 2333-2581) January 2017, Volume 3, No. 1, pp. 25-34 Doi: 10.15341/mese(2333-2581)/01.03.2017/004 Academic Star Publishing Company, 2017 www.academicstar.us

Hydrocarbon and Non-Hydrocarbon WAG Processes: A Simulation Approach Abdulrazag Y. Zekri1, Shedid A. Shedid2, and Abdalla A. Abed3 1. United Arab Emirates University, Al-Ain UAE, UAE 2. American University in Cairo (AUC), Cairo, Egypt 3. ADMA, Abu Dhabi, UAE Abstract: Development and application of enhanced oil recovery (EOR) processes in layered heterogeneous carbonate reservoirs has been considered a real challenge and a difficult endeavor. A multi-layered heterogeneous carbonate oil reservoir was screened and selected as a good candidate to investigate the feasibility of Water-Alternating-Gas (WAG) process using both hydrocarbon and non-hydrocarbon gases. An integrated reservoir characterization model and the pertinent transformed reservoir simulation history matched model were developed. The main objective of this work is to define the development process that could provide the maximum ultimate recovery factor of more than 70% IOIP. This could increase the total technical reserves by 30 % over the reserves based on classical water flooding reserves. The attained results are used to conclude that the life of the field could be extended and almost doubled. The results also indicated that the best technical development process that provides maximum ultimate recovery factor of more than 70% was the H2S-WAG development process. The enriched-WAG development scheme can be designed to give an equivalent ultimate recovery factor by enriching the gas. The N2-WAG development process gives a relatively poor recovery factor. This is the lowest of all the Non-hydrocarbon Gas Injection (NHGI-WAG) development processes investigated. Key words: carbon dioxide, hydrogen sulphide, nitrogen, reservoir simulation, rich hydrocarbon gas

1. Introduction The main and common goal of a full field development plan is to maximize ultimate oil recovery factor and minimize capital and operating expenditures (CAPEX & OPEX) or simply to maximize techno-economical ultimate recovery factor. The achievement of this goal requires identification, assessment, selection, definition and execution the optimum multiphase full field development option [1]. Carbon dioxide and Water-Alternating-Gas (WAG) processes have been applied successfully to increase theoil recovery all over the world [3, 7, 9, 12, 13].

Corresponding author: Abdulrazag Y. Zekri, Ph.D. in Petroleum Engineering, Professor, research areas/interests: environmental problems associated with oil and gas production, enhanced oil recovery. E-mail: [email protected].

Shedid et al. [5] conducted a laboratory study using whole core to investigate the effect of miscible CO2 slug sizes of 0.0, 0.15, 0.30, 0.45 and 1.00 PV of CO2 injection. The ultimate recovery was found to be between 66% and 96%. Zekri et al. [11, 13] studied the effect of pressure, oil saturation, core permeability, throughput, asphaltene deposition and petrophysical properties of tight carbonates on CO2 flooding. The attained results showed that an optimum amount of SC-CO2 is required to maximize the oil displacement from a specific area and it is a function of permeability, pressure, temperature, and flow rate. In addition, dissolution of calcite grains improved the permeability but precipitation of calcite downstream resulted in reduction of permeability and consequently reduced injectivity [2]. A more oil recovery could be obtained if CO2 flooding process could be started at higher oil saturation, and better

26

Hydrocarbon and Non-Hydrocarbon WAG Processes: A Simulation Approach

displacement efficiency was improved with higher permeability reservoirs. Shedid et al. [6, 10] conducted laboratory investigation of initial oil saturation and oil viscosity on oil recovery using Carbon Dioxide (CO2) miscible flooding through actual limestone core samples and actual reservoir fluids under simulated reservoir conditions of pressure and temperature. The results indicated that higher initial oil saturation provided higher oil recovery while higher oil viscosity produced lower oil recovery by CO2 flooding. Zekri et al. [12] conducted a laboratory study to investigate the influence of super-critical carbon dioxide (SC-CO2) flooding on rock, fluid and rock-fluid properties. The results indicated that SC-CO2 flooding reduced porosity and permeability, increased wettability of water-wet system to more water-wet condition, and reduced interfacial tension (IFT) between the oil-water systems. The ultimate recovery factor is implicitly a function of a development scheme, a development process scheme, a reservoir management plan and a business plan including a multiphase execution plan [9]. It is explicitly a function of areal, vertical and displacement efficiencies. The main components of the full field development option identified for assessment are summarized as follows: (1) Field development scheme involves: (a) surface well patterns, and (b) subsurface well bore patterns. (2) Field development processinvolves: (a) EOR processes, and (b) surface facilities (3) Reservoir management planinvolves: (a) production/injection plan, (b) reservoir monitoring and reservoir surveillance plan, and (c) technologies and studies plan. (4) Phased full field business plan includes: (a) the available production/injection profiles, (b) the recovery profiles targeting the ultimate recovery, (c) full field implementation road map, and (d) the economics profile based on an economical modelconsidering the general strategy of the organization

The reservoir simulation model used to assess the identified development options is an element compositional model. The input data of the integrated reservoir characterization model are actual data obtained from a producing UAE carbonate oil reservoir. The dependent variables that have to be identified, assessed and optimized are numerous. Advanced coupled subsurface–surface simulation models could be used to assess the variables. A strategical economic model is then used to select the optimum field development plan. The UAE University at Al-Ain city, the United Arab Emerits (UAE), has a research program on the development of technologies to investigate and utilize the non-hydrocarbon gases (NHG) and Enhanced Oil Recovery (EOR) injectants as follows: (a) In 2002, a reservoir simulation study was conducted where hydrogen sulphide gas process was utilized as the EOR process, and (b) In 2004, a research project on carbon dioxide (CO2) utilization was conducted where lab tests, process studies and fluid properties studies were made [4]. Sour and/or acid gas injection EOR processes may cause precipitation of bitumen and chemical/physical reaction between reservoir fluids and rocks [8]. These reactions may lead to modifications of fluid, rock and rock fluid properties. Presently it is very difficult to model petrophysical properties and wettability changes and investigate these variables using explicitly the current models. Laboratory studies are normally conducted and the effects are accordingly considered. The physical properties of the non-hydrocarbon gases and the Equation of State (EOS) used to predict these properties are of great importance. Great care should be taken to tunethe selected EOS using accurate laboratory data. The following properties for sour and/or acid gas components were calculated at pressure of 4175 psi and temperature of 250 °F, which maybe referenced in Table 1.


Table 1 Sour and/or acid gas components properties.

Gas

Bg(Bbls/Mscf)

ρg(lbs/ft )

H2S

0.39779

40.096

0.22162 0.47601

CO2

0.55209

37.833

0.06021 0.65211

3

μg(cp)

Z

C1

0.85229

8.80978

0.02144 1.00712

N2

0.98214

13.3911

0.02751 1.15003

AG/RG

0.88055

10.76356 0.02330 0.97126

2. Reservoir Modeling For a selected reservoir, an element reservoir simulation model was developed based on a transformed integrated reservoir characterization model. Before using in the current work, the integrated reservoir characterization model and the reservoir simulation model were updated and quality assured. Fig. 1 shows 3-D gridding system and well locations in the model. The integrated reservoir characterization model and the pertinent transformed reservoir simulation history matched model were established based on the production history of the reservoir. Model quality assured and checked through history machining of oil production rates and pressures versus time to develop the required model that has been used in this study.

3. Identification of Different Development Options To assess and select the optimum development option that maximizes the ultimate recovery viable development options with the objective development process will be identified. All dependent variables affecting the results of the study are considered when defining the constraints.

Fig. 1 Developed 3-D simulation model and well locations.

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In the study, the main objective is to select the development option that will maximize ultimate recovery factor for the EOR development processes of the NHGI comprising H2S, CO2 and N2. Based on the guidelines, the following main development options can be identified for the assessment study:  EOR miscible/immiscible gas injection processes for the NHG N2, CO2 and H2S.  EOR miscible/immiscible gas injection processes for C1, lean gas and rich gas. These cases will be treated as reference cases.  For each EOR process, the following development options will be identified for assessment: * Gas continuous injection * Gas WAG/GAW * Gas combined with water, SWAG. The following other development options were investigated but were not considered for technical assessment:  Gas slug injection  Gas mixture Tables 2A to 2D present the development options identified for further study and assessment.

4. Analysis and Discussion of Results Identification and assessment of development options were conducted. Selection, definition and execution of the assessed development options are normally conducted where an economical model is applied. The development options are classified and grouped based on the main components of the development options comprising the development scheme, the development process, the reservoir management plan including production-injection profiles and the business plan including implementation and operating plans. The development options studied were classified based on the EOR development processes. The emphasis is made on the following: (a) H2S-EOR development process, (b) CO2-EOR development


28

process, (c) N2-EOR development process, and (d) Table 2A

AG/RG-EOR.

Development options identification. Development Option Identification Development Scheme

Development Option

H2o

Table 2B

Pattern

Spacing (Ft)

Direct Line Drive

2460

Development Process

Reservoir Management

Group

Injectant

Production Rate (Stb/D)

Upper

-

-

Injection ( MBBLS/D or MMSCF/D) -

Lower

H2o

4000

8

Field

H2o

4000

8

Upper

-

-

-

Lower

H2S

4000

12.5

Field

H2S

4000

12.5

Upper

H2O

-

4

Lower

H2S

4000

12.5

Field

H2O +H2S

4000

4 + 12.5

Upper

-

-

-

Lower

H2S H2O

4000

Lower

H2O H2S

-

8, 25

Field

H2O

4000

8, 25

Development options identification. H2S

H2S-H2O

H2S-WAG

Direct line drive

Direct line drive

Direct line drive

2460

2460

2460

H2S

25,

8

Table 2C Development options identification.

t

CO2-H2O

Direct line drive

Direct line drive

2460

2460

Upper

-

-

-

Lower

CO2

4000

12.5

Field

CO2

4000

12.5

Upper

CO2

-

4

Lower

CO2

4000

12.5

Field

H2O+CO2

4000

4 + 12.5

Upper CO2-WAG

N2

N2-H2O

N2-WAG

Direct line drive

Direct line drive

Direct line drive

Direct line drive

2460

2460

2460

2460

-

-

-

4000

25, 8

H2O CO2

-

8, 25

Lower

CO2

Lower

H2O

Field

H2O CO2

4000

8, 25

Upper

-

-

-

Lower

N2

4000

12.5

Field

N2

4000

12.5

Upper

N2

-

4

Lower

N2

4000

12.5

Field

H2O+N2

4000

4 + 12.5

Upper

-

-

-

Lower

N2

H2O

4000

25,

8

Lower

H2O N2

-

8,

25

Field

H2O N2

4000

8,

25


29

Table 2D Development options identification.

Direct line drive

AG/RG

AG/RG - H2O

2460

Direct line drive

2460

Upper

-

-

-

Lower

AG/RG

4000

12.5

Field

AG/RG

4000

12.5

Upper

AG/RG

-

4

Lower

AG/RG H2O+ AG/RG AG/RG H2O H2O AG/RG H2O AG/RG

4000

12.5

4000

4 + 12.5

-

-

Field Upper Lower AG/RG - WAG

Direct line drive

2460

Lower Field

Also, the following development options were studied and will be used as base and/or reference cases: (a) Water injection development process, and (b) Lean gas/C1 injection development process. The indicated development options can be grouped to be able to compare the production injection profiles and finally the ultimate recovery factor. The following groups/types are adopted: (1) Water injection development options, (2) Gas injection development options, (3) WAG development options, and (4) SWAG development options. A water development option is referenced and included. The initial properties of the injectants and reservoir fluid could be summarized in Table 3. 4.1 Gas Injection Development Process The gas composition and reservoir pressure and temperature are the main variables that could define the efficiency of any gas injection development process when the gas is a single component, the properties of the gas under reservoir pressure and temperature will Table 3 Initial properties of injectants and reservoir fluid. Viscosity ratio Density difference Process (μo/μg) cp/cp (ρo-ρg )lbs/ft3 H2S 0.18/0.22 38-40 CO2

0.18/0.06

38-37.8

N2

0.18/0.0275

38-13.4

AG/RG

0.18/0.023

38-10.8

4000

25,

8

-

8,

25

4000

8,

25

define the efficiency of the process. When the gas is a multi-component gas the mole percent of individual components should be selected to achieve the designated recovery efficiency. This may lead to gas enrichments if the composition is unfavorable. Fig. 2 presents recovery profiles and Table 4 presents recovery factors for different gas injection processes. The recovery factor after 50 years for different processes is listed in Table 4. To achieve a high recovery factor, the displacing fluid should achieve high areal, vertical and displacement efficiency. This means that viscous to gravity forces ratio R(V/G), the mobility ratio (M), and the viscous to capillary forces ratio, capillary number, the minimum miscibility pressure (MMP) and the technical rate are favorable. The main variables of the above processes that affect the recovery factors could be summarized in Table 5. The recovery of H2S gas injection process is relatively high due to the followings: Table 4 Recovery factor for different processes.

Process

Recovery Factor %

H2S

56.5

CO2

55.4

N2

27.1

AG/RG

55.4

H2O

50.8


30

Fig. 2 Recovery profiles for different gas injection processes. Table 5 Processes and variables affecting recovery factor. Process H2S

CO2

N2

AG/RG

Results

- Increase in oil viscosity - Swelling of the oil - Increase in oil density - Lowering of the interfacial tension. Miscibility with oil is achieved - Reduction in oil viscosity - Swelling of the oil - Minor change in oil density - Lowering of the interfacial tension. Miscibility with oil is achieved. - Viscosity ratio >1. - N2-Oil is immiscible. - Vertical viscous forces is higher than gravity forces. - Capillary number is not high - Large reduction in oil viscosity. Mobility ratio is most probably less than one. - RG is miscible at reservoir pressure. - Swelling of the oil. - Reduction in oil density.

(1) In the neighborhood of the producing well, the miscible conditions are achieved. The mobility ratio is favorable and the viscous to gravity ratio is most probably also favorable leading to relatively good areal and vertical sweep efficiencies. (2) In all flooded layers, the areal sweep efficiency is apparently high. 4.2 SWAG injection Development Process Injecting gas and water simultaneously in a layered

reservoir where gas is injected in the lower low permeable layers and water was also injected in the lower less permeable layers. The fluid flow pattern could be as follows: (1) Multiphase flow in the upper high permeability layers. (2) Single-phase oil, then two phase, oil and gas, after gas breakthrough and finally multiphase flow, oil, gas and water after water breakthrough in the neighborhood of the producers. Of course, the time of


fluid breakthrough will depend on the type of fluid and composition of gas. Fig. 3 presents recovery profiles and Table 6 presents recovery factors for different SWAG injection processes. The main variables of these processes that affect the recovery factors of the above processes could be summarized in Table 7.

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Table 6 The recovery factors after 50 years for different SWAG processes. Process

Recovery Factor

H2S-SWAG

65.6

CO2-SWAG

64.5

N2-SWAG

30.5

AG/RG-SWAG

59

H2O

50.8

Fig. 3 Recovery profiles for different SWAG injection processes. Table 7 Processes and variables affecting recovery factor. Process H2S - SWAG

CO2- SWAG

N2- SWAG

AG/RG- SWAG

Results - The density of the injectants is higher than the oil density. - Downward flow due to higher gravity forces improves the recovery factor. - The viscosity ratio and/or mobility ratio improve the vertical sweep efficiency. - Large reduction in oil viscosity. - Swelling of the oil. - Minor change in oil density - Lowering of the interfacial tension. Miscibility is achieved. - Water viscosity is higher than oil viscosity leading to favorable H2O-oil mobility. - The swelling of N2 is relatively poor. - The miscibility pressure is very high. - Viscous to gravity ratio is unfavorable leading to poor areal sweep efficiency. - Viscosity ratio and most probably mobility ratio are unfavorable leading to poor areal sweep efficiency. - Interfacial tension is relatively high leading to high residual oil saturation. - Override of the injected gas in the area between producers and injectors. - Volumetric sweep efficiency of the lower part is lower. - Recovery increase when the GOR and WC increases and the injected volume increases.

32


4.3 WAG Injection Development Process Water alternating gas injection process was found to better optimize the microscopic and macroscopic displacement efficiencies. However, different gases give different recovery factors depending on pertinent mobility ratio, viscous to gravity ratio and viscous to capillary pressure ratio. The fluid flow for a WAG injection development process in the studied reservoir is a multiphase fluid flow in the neighborhood of the injector, in the high permeability layers and in the neighborhood of the producers.

The following WAG processes were identified and studied: (a) H2S-WAG development process, (b) CO2-WAG development process, (c) N2-WAG development process, and (d) AG/RG-WAG development process. The cycle time of a WAG process could have a big effect on the control of WAG performance process, especially when there is a big heterogeneity and anisotropy in the rock model. It is believed that WAG process will have a better control compared to SWAG process on viscous fingering and viscous override. Fig. 4 presents recovery profiles and Table 8 presents recovery factors for different WAG injection processes.

Fig. 4 Recovery profiles for different WAG injection processes.

Comparison the oil recovery factor using different processes, as shown in Table 8, reveals that the N2-WAG is the worst choice due to the pressure requirement to achieve miscibility with nitrogen is quite high. Normally around 5000 psia, therefore in our case N2 did not help in oil recovery in the contrary it acts as barrier to the follow of oil as you created three phase flow oil, gas, and water

Table 8 The recovery factors after 50 years for different WAG processes. Process

Recovery Factor %

H2S - WAG

70.1

CO2- WAG

64.5

N2- WAG

33.9

RG- WAG

60.0

H2O

50.8


The main variables of these processes that affect the recovery factors of the above processes could be Table 9

33

summarized in Table 9.

Processes and variables affecting recovery factor.

Process H2S-WAG

CO2-WAG

N2-WAG AG/RG-WAG

Results - Lower part is displaced vertically in the middle between the producers and injectors. - Upper part is displaced aerially and vertically - Mobility, R (V/G) and viscous to capillary forces ratios are more favorable. - CO2 swelling in the neighborhood of the producers, injectors and the upper part. - Miscibility in the neighborhood of the producers, injectors and the upper part. - Inter region flow from the upper to lower based on the net viscous, gravity and capillary pressure forces. - Effect of viscosity reduction on mobility ratio. - Effect of interfacial tension reduction on capillary pressure forces. - Poor areal, vertical and displacement efficiency where the process is immiscible. - The microscopic and macroscopic displacement ratios are unfavorable - Microscopic and macroscopic functions depend on composition and fluid and rock-fluid properties. - The richness of the gas will theoretically define the recovery.

5. Conclusions This study is designed to investigate the feasibility of Water-Alternating-Gas (WAG) using hydrocarbon and non-hydrocarbon gases in layered heterogeneous carbonate oil reservoir. The attained results of this study are used to draw the following conclusions: (1) Quality assurance of used models is necessary for the optimization of Water-Alternating-Gas (WAG) process. This includes integrated reservoir characterization model and good matched subsurface reservoir simulation model to be coupled with surface simulation model and a strategic economical model. (2) All variables of the micro-displacement and macro-displacement efficiencies should be investigated as dependent variables for estimating the ultimate recovery factor or the independent variable. (3) H2S-WAG injection process is technically the optimum process for the reservoir under development, followed by CO2-WAG, rich gas WAG, water injection, and N2-WAG process. The H2S-WAG process can be applied to other similar reservoirs. (4) The development scheme is strongly dependent on heterogeneity of reservoir rock and fluid models as well as the production-injection profile as a business plan.

(5) The development phases are strongly dependent on reservoir performance and reservoir management together with reservoir development strategy. (6) The technical constraints could be identified, assessed and selected independently. Integrated optimization studies could be then conducted to select the optimum development option.

Acknowledgment The authors would like to express their appreciation for the financial support received from ADNOC, ADCO, ADNOC R&D Committee.Many thanks to UAEU research sector for their support. Nomenclature AG/RG Associate Gas/Rich Gas Bg Gas Formation Volume Factor (BBLS/MSCF) EOR Enhanced Oil Recovery EOS Equation of State FWPT Field Water Production Total (BBLS) FGPT Field Gas Production Total (MMSCF) FOPT Field Oil Production Total (MMSTB) FWIR Field Water Injection Rate (MMBBLS) FWCT Field Water Cut (%) FGIR Field Gas Injection Rate (MMSCF/D) FPR Field Pressure (PSIG) FOPR Field Oil Production Rate (STB/D) FGOR Field Gas Oil Ratio (SCF/STB) GAW Gas Alternating Water IFT Interfacial Tension, dyne/cm NHG Non Hydrocarbon Gas


34

NHGI Non Hydrocarbon Gas Injection OWCOil Water Contact (FT) OGIP Original Gas in Place (MMSCF) PV Pore Volume R (V/G) Viscous to Gravity Forces Ratio SWAG Simultaneous Water Alternating Gas WAG Water Alternating Gas WC Water cut (%) WORWater Oil Ratio Z Gas Deviation Factor ρg Gas Density (LBS/FT3 ) ρo Oil Density (LBS/FT3 ) μg Gas Viscosity (CP) μo Oil Viscosity (CP)

[6]

[7]

[8]

Abbreviations [9] CAPEX OPEX NHG SC-CO2 WAG

Capital Expenditure Operating Expenditure Non-Hydrocarbon Gas Super-Critical Carbon Dioxide Water Alternating Gas

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