An Independent Analysis of the Performance Characteristics and Economic Outcomes of the Liza Phase 1 Development Offshore Guyana Using Public Domain Data

2021 ◽  
Author(s):  
Simon Paul ◽  
Kadija Dyall ◽  
Quinn Gabriel
Keyword(s):  
Oil Recovery ◽  
Dynamic Models ◽  
Computer Modelling ◽  
Phase 1 ◽  
Water Injection ◽  
Public Domain ◽  
Gas Production ◽  
Google Earth ◽  
Reservoir Rock ◽  
Original Oil In Place

Abstract An attempt was made to independently verify the proposed performance of the Liza 1 field using only data available in the public domain. The data used in modelling was sourced from news reports, company disclosures and the analogue Jubilee field in Ghana. Reservoir rock and fluid data from Jubilee Field was deemed an appropriate fit because of the corroboration provided by the Atlantic Drift Theory. A major challenge in creating the model, was determining the aerial extent of the field. According to Yang and Escalona (2011), the subsurface can be reasonably approximated using the surface topography which is possible via the use of GIS software. Google Earth Pro software was used to estimate the coordinates and areal extent of the Liza 1 reservoir. A scaled image of the field location showing the Guyana coastline was re-sized to fit the coastline in Google Pro and then the coordinates for the Liza field and wildcat well locations were estimated. This was used to create the isopach map and set reservoir boundaries to create the static and dynamic models in Schlumberger's Petrel E & P Software Platform (2017) and Computer Modelling Group IMEX Black Oil and Unconventional Simulator CMG IMEX (2016). The initialized model investigated the reservoir performance with and without pressure maintenance over a twenty (20) year period. The original oil in place (OOIP) estimated by the model was 7% larger than the OOIP estimated by ExxonMobil for Liza field. The model produced 35% of the OOIP compared to 50% of OOIP as forecasted by the operators. (See Table 1). The factors that strongly influenced this outcome were, the well positioning and the water injection rates. A significant percentage of the oil remained unproduced in the lower layers of the model after the 20-year period. Time did not permit further modelling to improve the performance of the model. Table 1 Comparison of The Created Model and ExxonMobil's Proposal for Liza. Property ExxonMobil's statement on Liza field Modelled field Result Original Oil in Place (MMbbl) 896 967 Oil Recovery Factor (%) 50 35 Gas production from the model would be used as gas injection from three injector wells and as fuel for the proposed 200 MW power plant for Guyana. Even so, significant volumes of natural gas remained unallocated and subsequently a valuable resource may have to be flared.

Instow: A Full-Field, Multipatterned Alkaline-Surfactant-Polymer Flood—Analyses and Comparison of Phases 1 and 2

2021 ◽  
pp. 1-15
Author(s):  
M. J. Pitts ◽  
E. Dean ◽  
K. Wyatt ◽  
E. Skeans ◽  
D. Deo ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Phase 1 ◽  
Water Injection ◽  
Phase 2 ◽  
Full Field ◽  
Two Phases ◽  
Original Oil In Place ◽  
Total Oil ◽  
Operation Cost ◽  
Alkaline Surfactant Polymer

Summary An alkaline-surfactant-polymer (ASP) project in the Instow field, Upper Shaunavon Formation in Saskatchewan, Canada, was planned in three phases. The first two multiwell pattern phases are nearing completion. Beginning in 2007, an ASP solution was injected into Phase 1. Phase 1 polymer drive injection began in 2011 after injection of 37% pore volume (PV) ASP solution. Coincident with the polymer drive injection into Phase 1, Phase 2 ASP solution injection began. Phase 2 polymer drive began in 2016 after injection of 55% PV ASP solution. Polymer solution injection for the polymer drives of both phases continues in both phases with Phase 1 and Phase 2 injected volumes being 55 and 42% PV as of August 2019, respectively. Phase 1 and Phase 2 oil cut response to ASP injection showed an increase of approximately four times from 3.2% to a peak of 13.0% for Phase 1 and Phase 2 oil cut increased from 1.8% to a peak of 14.8%, approximately eightfold. Oil rates increased from approximately 3200 m3/m (20 127 bbl/m) at the end of water injection to a peak of 8300 m3/m (52 220 bbl/m) in Phase 1 and from 1230 m3/m (7 736 bbl/m) to 6332 m3/m (39 827 bbl/m) in Phase 2. Phase 1 pattern analysis indicates that the PV of ASP solution injected varied from 13% to 54% PV of ASP. Oil recoveries after the start of ASP solution injection in the different patterns ranged from 2.3% original oil in place (OOIP) up to 21.3% OOIP with lower oil recoveries generally correlating with lower volumes of ASP solution injected. Wells in common to the two phases of the project show increased oil cut and oil rate responses to chemical injection from both Phases 1 and 2. Total oil recovery as of August 2019 is 60% OOIP for Phase 1 and 62% OOIP for Phase 2. Phase 1 economic analysis indicated chemical and operation cost was approximately CAD 26/bbl, resulting in the decision to move forward with Phase 2.

Acoustic Emissions as a Tool for Hydraulic Fracture Location: Experience at the Fenton Hill Hot Dry Rock Site

1982 ◽  
Vol 22 (04) ◽  
pp. 523-530 ◽  
Author(s):  
James N. Albright ◽  
Christopher F. Pearson
Keyword(s):  
Water Injection ◽  
Acoustic Emissions ◽  
Reservoir Rock ◽  
Time Interval ◽  
Reservoir Pressure ◽  
Simulation Studies ◽  
Total Recovery ◽  
Tank Farm ◽  
Niger River ◽  
Original Oil In Place

Summary The Delta South field is situated on an anticlinal high, positioned between two major growth faults. The field is in an offshore environment in the Niger Delta area. The G-2 and G-3 reservoirs contain about 90% of the field's reserves. Primary production from these reservoirs is by gravity drainage and gas-cap expansion. The effect of water influx on the total recovery mechanism has been minimal. Reservoir engineering studies indicate primary depletion will permit the recovery of 30% of the original oil in place (OOIP). The installation of a waterflood pressure maintenance project should allow the ultimate recovery to be increased to approximately 50% of OOIP. Introduction The Delta South field was discovered in May 1965 and is situated approximately 3 miles offshore the coastline of Bendel State, Nigeria (Fig. 1). The field is in a complex of 10 offshore fields operated by Gulf Oil Co. (Nigeria) Ltd. (GOCON) in conjunction with the Nigerian Natl. Petroleum Co. (NNPC), which is the majority partner. Fig. 1 shows that the field is adjacent to the GOCON/NNPC Escravos River Tank Farm. The field is in a nearshore surf area, and the water depth varies from 10 to 16 A. Production from the field is derived principally from the G-2 and G-3 sands. The G-2 reservoir is at an average depth of 8,920 ft subsea and is underlain by the G-3 reservoir. The two sands are separated by an intervening 100-ft-thick shale member that excludes pressure and fluid communication. The two reservoirs are similar in structure and rock and fluid properties. The Delta South field commenced production in March 1968. The production of 21 % of OOIP from G-2 by March 1978 had resulted in a reservoir pressure decline of 33%. The production of 29% of OOIP from G-3 during this same time interval resulted in a reservoir pressure decline of 39%. Reservoir rock and fluid property data acquisition commenced in 1967 when Delta South Well 8 was cored with a rubber sleeve core barrel. In 1972 Delta South Well 13 was cored. Reservoir oil fluid sampling was done in 1968 and again in 1979. The initial sampling was a prelude to simulation studies carried out at the Gulf Research and Development Co. facilities in 1970. The results of these and subsequent simulation studies are presented in a separate paper (Part 2). The studies have indicated the need for the installation of a water injection project in the field. The necessary approvals have been obtained, and project start-up was scheduled for late 1981. This paper describes the Delta South field, the producing history, the expected results, the injection/producing method, and the facilities to be installed. Part 2 describes the reservoir simulation work and the results of those investigations. Field Description The Delta South G-2 and G-3 sands were deposited dun ing mid-Miocene time. These sands are part of an extensive barrier bar system related to the ancient Niger River. Since Eocene time, the depositional forces prevalent at the confluence of the Niger River and the Bight of Benin were dominated by waves and tides. These types of deltaic deposits often produce reservoir rock of excellent quality. First, wave and tidal current velocities are relatively constant, which results in a fairly uniform grain-size distribution. Second, the constant reworking of the sediments tends to remove clay particles. Third, the sand bodies tend to have a sheet on blanket geometry (sands can be correlated easily for at least 4 miles along strike and 2 miles along the dip). JPT P. 141^

scholarly journals Microorganisms’ effect on the wettability of carbonate oil-wet surfaces: implications for MEOR, smart water injection and reservoir souring mitigation strategies

2019 ◽  
Vol 10 (4) ◽  
pp. 1539-1550 ◽  
Author(s):  
Moein Jahanbani Veshareh ◽  
Shahab Ayatollahi
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Oil Industry ◽  
Gas Production ◽  
Mitigation Strategies ◽  
Decision Makers ◽  
Production Costs ◽  
Smart Water ◽  
Fractured Carbonate ◽  
The Individual

Abstract In upstream oil industry, microorganisms arise some opportunities and challenges. They can increase oil recovery through microbial enhanced oil recovery (MEOR) mechanisms, or they can increase production costs and risks through reservoir souring process due to H2S gas production. MEOR is mostly known by bioproducts such as biosurfactant or processes such as bioclogging or biodegradation. On the other hand, when it comes to treatment of reservoir souring, the only objective is to inhibit reservoir souring. These perceptions are mainly because decision makers are not aware of the effect microorganisms’ cell can individually have on the wettability. In this work, we study the individual effect of different microorganisms’ cells on the wettability of oil-wet calcite and dolomite surfaces. Moreover, we study the effect of two different biosurfactants (surfactin and rhamnolipid) in two different salinities. We show that hydrophobe microorganisms can change the wettability of calcite and dolomite oil-wet surfaces toward water-wet and neutral-wet states, respectively. In the case of biosurfactant, we illustrate that the ability of a biosurfactant to change the wettability depends on salinity and its hydrophilic–hydrophobic balance (HLB). In distilled water, surfactin (high HLB) can change the wettability to a strongly water-wet state, while rhamnolipid only changes the wettability to a neutral-wet state (low HLB). In the seawater, surfactin is not able to change the wettability, while rhamnolipid changes the wettability to a strongly water-wet state. These results help reservoir managers who deal with fractured carbonate reservoirs to design a more effective MEOR plan and/or reservoir souring treatment strategy.

Simultaneous Production of Gas Cap and Oil Column With Water Injection at the Gas/Oil Contact

1999 ◽  
Vol 2 (05) ◽  
pp. 412-419 ◽  
Author(s):  
T.C. Billiter ◽  
A.K. Dandona
Keyword(s):  
Oil Recovery ◽  
Pressure Support ◽  
Gas Production ◽  
Oil Field ◽  
Oil Reservoir ◽  
Horizontal Distance ◽  
Gas Oil ◽  
Simultaneous Production ◽  
Original Oil In Place ◽  
Dip Angle

Summary The conventional way to produce an oil reservoir that has a gas cap is to produce only from the oil column while keeping the gas cap in place so that it can expand to provide pressure support. Depending upon the geometry, reservoir dip angle, and oil production rates, gas can either cone down to the oil producers or breakthrough as a front, leading to substantial increases in the gas-oil ratios of the oil producers. This paper presents a unique production methodology of simultaneously producing the gas cap and oil column while injecting water at the gas-oil contact to create a water barrier to separate the gas cap and oil column. This methodology has application in reservoirs with a low-dip angle, large gas cap, and a low residual gas saturation to water. It is demonstrated that the net present value of the project is improved if there is an immediate market for gas. Geostatistical reservoir models are used to demonstrate that the gas cap recovery is minimally impacted by heterogeneities. Introduction of the Concept The conventional way to produce an oil reservoir that has a gas cap is to produce the oil column while minimizing production from the gas cap. During the pressure depletion of the reservoir, the gas cap will expand to provide pressure or energy support. After the oil column is depleted, the gas cap is "blown down." In developing a production strategy for an oil reservoir with a large gas cap, a low-dip angle, and an available gas market, simultaneous waterflooding of the gas cap and oil column was evaluated. The water is injected at the gas-oil contact at rates high enough to overcome gravity effects and thus, the water displaces the gas up dip. In addition to providing pressure support, the created water wall separates the gas cap and the oil column regions. Since the development plan calls for the use of electrical submersible pumps (ESPs) in the oil producing wells, it is imperative to keep the gas production volumes from these oil wells at low levels so the ESPs will operate smoothly. As such, it is critical to control the downward migration of the gas cap. To maintain the reservoir pressure, water is injected not only at the gas-oil contact but also around the downdip periphery of the oil column to support the oil withdrawal rates. A simplistic representation of the simulated structure is shown in Fig. 1. This figure shows the location of the gas-oil contact, along with the location of the water injector at the gas-oil contact and of the gas cap producer. The reservoir considered in this study has a dip angle of 2°. For the purposes of illustration the dip angle has been exaggerated in Fig. 1. The horizontal distance between the injector and producer is 12,155 feet. The structural elevation difference between these two wells is 425 feet. Taking into account the density difference between the water and gas, the injected water must overcome a gravity component of 149 psi in addition to the energy required for the water to displace the gas. The possibility of injecting water at high enough rates to overcome both the gravity and displacement components is shown in this paper. The main objective of this paper is to present the concept of simultaneously producing the gas cap and oil column while injecting water at the gas-oil contact. The application of this concept for a newly discovered, offshore oil field has been studied. In this study, the majority of the effort was dedicated to theoretically proving this concept, as opposed to optimizing the number of wells and placement of wells to increase the recovery factors for oil and gas. This production methodology should be applicable to other reservoirs with similar characteristics. Partial Proof of Concept A literature survey indicated that the simultaneous production of the gas cap and oil column while injecting water at the gas-oil contact, has never been documented. However, four case histories were found in which water was injected at the gas-oil contact for the sole purpose of preventing the migration of the gas cap down structure. By preventing this migration, increased oil recoveries were realized. In these four cases, the gas cap was not produced during the depletion of the oil column. One successful application of this production methodology was to the Adena field in the Denver basin in 1965.1 By injecting water at the gas-oil contact, the operator was able to keep the producing gas-oil ratio value close to the solution gas-oil ratio value for an extended time. The ultimate oil recovery was estimated to be 47% of the original oil in place. The methodology of injecting water at the gas-oil contact was also applied in seven of the oil reservoirs of the Algyo Field in Hungary.2 These seven reservoirs are thin oil edge zones with large gas caps. The operators of this field were able to increase oil recovery by over 10% of original oil in place by using this methodology. In the Canadian oil field Kaybob South, the injection of water at the gas-oil contact was studied by Deboni and Field.3 They used numerical simulation to determine that a waterflood can be successfully implemented adjacent to a gas cap if a proper water "fence" is established between the gas cap and oil column. The authors concluded that an additional 10% of the oil in place can be recovered.

scholarly journals Experimental study of the performances of commercial surfactants in reducing interfacial tension and wettability alteration in the process of chemical water injection into carbonate reservoirs

2019 ◽  
Vol 10 (4) ◽  
pp. 1551-1563 ◽  
Author(s):  
Siamak Najimi ◽  
Iman Nowrouzi ◽  
Abbas Khaksar Manshad ◽  
Amir H. Mohammadi
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Oil Recovery ◽  
Saline Water ◽  
Water Injection ◽  
Reservoir Rock ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Core Flooding ◽  
Chemical Water

Abstract Surfactants are used in the process of chemical water injection to reduce interfacial tension of water and oil and consequently decrease the capillary pressure in the reservoir. However, other mechanisms such as altering the wettability of the reservoir rock, creating foam and forming a stable emulsion are also other mechanisms of the surfactants flooding. In this study, the effects of three commercially available surfactants, namely AN-120, NX-1510 and TR-880, in different concentrations on interfacial tension of water and oil, the wettability of the reservoir rock and, ultimately, the increase in oil recovery based on pendant drop experiments, contact angle and carbonate core flooding have been investigated. The effects of concentration, temperature, pressure and salinity on the performances of these surfactants have also been shown. The results, in addition to confirming the capability of the surfactants to reduce interfacial tension and altering the wettability to hydrophilicity, show that the TR-880 has the better ability to reduce interfacial tension than AN-120 and NX-1510, and in the alteration of wettability the smallest contact angle was obtained by dissolving 1000 ppm of surfactant NX-1510. Also, the results of interfacial tension tests confirm the better performances of these surfactants in formation salinity and high salinity. Additionally, a total of 72% recovery was achieved with a secondary saline water flooding and flooding with a 1000 ppm of TR-880 surfactant.

Experimental Investigation of the Impact of Crude Oil and Rock on Improved Recovery by Low Salinity Water Injection

2021 ◽  
Author(s):  
Mohamed Alhammadi ◽  
Shehadeh Masalmeh Masalmeh ◽  
Budoor Al-Shehhi ◽  
Mehran Sohrabi ◽  
Amir Farzaneh
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Water Injection ◽  
Core Sample ◽  
Reservoir Rock ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Reservoir Conditions ◽  
Salinity Water ◽  
Low Salinity Water Injection

Abstract This study aims to compare the roles of rock and crude oil in improving recovery by low salinity water injection (LSWI) and, particularly, to explore the significance of micro-dispersion formation in LSWI performance. Core samples and crude oil were taken from two carbonate reservoirs (A and B) in Abu Dhabi. The oil samples were selected such that one of them would form micro-dispersion when in contact with low salinity brine while the other would not. A series of coreflood experiments was performed in secondary and tertiary modes under reservoir conditions. First, a core sample from reservoir A was initialized and aged with crude oil from reservoir A and a core sample from reservoir B was initialized and aged with crude oil from reservoir B. The cores were then swapped, and the performance of low salinity injection was tested using rock from reservoir A and crude from reservoir B, and vice versa. For the first set of experiments, we found that the crude oil sample capable of forming micro-dispersion (we call this oil "positive", from reservoir A) resulted in extra oil recovery in both secondary and tertiary LSWI modes, compared to high salinity flooding. Moreover, in the secondary LSWI mode we observed significant acceleration of oil production, with higher ultimate oil recovery (12.5%) compared to tertiary mode (6.5%). To ensure repeatability, the tertiary experiment was repeated, and the results were reproduced. The core flood test performed using "negative" crude oil that did not form micro-dispersion (from reservoir B) showed no improvement in oil recovery compared to high salinity waterflooding. In the "cross-over" experiments (when cores were swapped), the positive crude oil showed a similar improvement in oil recovery and the negative crude oil showed no improvement in oil recovery even though each of them was used with a core sample from the other reservoir. These results suggest that it is the properties of crude oil rather than the rock that play the greater role in oil recovery. These results suggest that the ability of crude oil to form micro-dispersion when contacted with low salinity water is an important factor in determining whether low salinity injection will lead to extra oil recovery during both secondary and tertiary LSWI. The pH and ionic composition of the core effluent were measured for all experiments and were unaffected by the combination of core and oil used in each experiment. This work provides new experimental evidence regarding real reservoir rock and oil under reservoir conditions. The novel crossover approach in which crude oil from one reservoir was tested in another reservoir rock was helpful for understanding the relative roles of crude oil and rock in the low salinity water mechanism. Our approach suggests a simple, rapid and low-cost methodology for screening target reservoirs for LSWI.

scholarly journals LABORATORY INVESTIGATION OF A NEW LIBYAN CHEMICAL EOR: Impact of GWLI on Relative Permeability, Wettability, Oil Recovery, Breakthrough and Fractional Flow

2019 ◽  
Vol 8 (2) ◽  
pp. 55-66
Author(s):  
Madi Abdullah Naser ◽  
Omar Azouza
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Water Injection ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Fractional Flow ◽  
Core Samples ◽  
Wide Range ◽  
Chemical Eor ◽  
The Impact

The greater demand for crude oil, the increased difficulty of discovering new reservoirs, and the desire to reduce dependence on imports have emphasized the need for enhanced recovery methods capable of economically producing the crude remaining in known reservoirs. Oil recovery from oil reservoirs may be improved by designing the composition and salinity of water injection. The process is sometimes referred to as sea or smart water injection. In this paper, a Gaberoun Water Leak Injection (GWLI) have been discovered and investigated as a new Libyan chemical EOR in laboratories on relative permeability, wettability, oil recovery, breakthrough, and fractional flow for carbonate and sandstone reservoirs. GWLI has several advantages which are relatively cheap, reliable, and available. GWLI potentially would have a wide range of applications in water injection such as wettability alteration. The equipment and the operating procedures were designed to simulate the reservoir condition. The experimental results indicate that, that the GWLI has caused the increasing of oil recovery in sandstone and carbonate core. The impact of GWLI on oil recovery in sandstone core samples was higher than carbonate core samples. The effect of acidity (pH) of GWLI on oil recovery in sandstone and carbonate core samples was higher when the pH is 5 than when the acidity is 10. Hopefully, the research findings can possibly be useful for references and for operating companies as an important source for understanding and visualizing the effects of pH, permeability, porosity, and wettability on oil recovery in reservoir rock using GWLI.

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