Successful Implementation of a Gas Injection Trial in a Low-Permeability Carbonate Reservoir, Offshore Qatar

2009 ◽  
Author(s):  
Kristian Mogensen ◽  
Soren Frank ◽  
Rashed Noman
Keyword(s):  
Gas Injection ◽  
Carbonate Reservoir ◽  
Low Permeability ◽  
Successful Implementation

Fishbone Stimulation Enhances Tight Carbonate Productivity

2021 ◽  
Vol 73 (07) ◽  
pp. 58-59
Author(s):  
Chris Carpenter
Keyword(s):  
Phase 1 ◽  
Carbonate Reservoir ◽  
Growth Strategy ◽  
Abu Dhabi ◽  
Low Permeability ◽  
Successful Implementation ◽  
Well Testing ◽  
Phase 2 ◽  
Carbonate Formation ◽  
Tight Carbonate

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202636, “Fishbone Stimulation: A Game Changer for Tight Carbonate Productivity Enhancement—Case Study of First Successful Implementation at ADNOC Onshore Fields,” by R.V. Rachapudi, SPE, S.S. Al-Jaberi, SPE, and M. Al Hashemi, SPE, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. The operator’s first successful installation of fishbone stimulation technology was aimed at establishing vertical communication between layers in a tight carbonate reservoir and maximizing the reservoir contact. Furthermore, the advanced stimulation technology connects natural fractures within the reservoir, bypasses near-wellbore damage, and allows the thin sublayers to produce. This technology requires running standard lower-completion tubing with fishbone subs preloaded with 40-ft needles and stimulation with the rig on site. Introduction The operator plans to develop tight carbonate reservoirs as part of its production growth strategy. Field Q is a 35×15-km field under development with a phased approach. Phase 1 was planned and production began in 2014. Phase 2 is being developed by drilling wells using the pad concept. Reservoir A, a tight carbonate formation with low permeability ranging from 1 to 3 md and porosity from 15 to 25%, is part of Phase 2 development. The aver-age thickness of Reservoir A is approximately 90 ft across the field, with seven sublayers. The major challenge of Reservoir A development is poor vertical communication and low permeability. Based on appraisal-well data, the average production rate per well is approximately 200 to 400 BOPD with a wellhead pressure of 200 psi. Therefore, appraisal-well testing confirmed the poor productivity of the wells. In addition, the wells are required to produce to the central facilities located in a Phase 1 area 18 km away from Phase 2. In summary, each Phase 2 well is required to be produced against a back-pressure of 500 to 600 psi. Fishbone Stimulation Technology Fishbone stimulation technology is an uncemented-liner rig-deployed completion stimulation system. The liner includes fishbone subs at fixed intervals, and each sub consists of four needles that will connect the sublayers by penetrating into the formation. The typical fishbone completion after installation and jetting the needles in formation is shown in Fig. 1.

A New Mathematical Model of Tight Formation for Productivity Transient Analysis with Additional Gas Driving

2021 ◽  
Author(s):  
Xiaoliang Zhao ◽  
Jiali Zhang ◽  
Xinwei Liao
Keyword(s):  
Transient Analysis ◽  
Phase Distribution ◽  
Gas Injection ◽  
Stress Sensitivity ◽  
Carbonate Reservoir ◽  
Low Permeability ◽  
Analysis Model ◽  
Damage Coefficient ◽  
Single Well ◽  
Permeability Damage

Abstract During the gas injection development of low-permeability carbonate reservoirs, due to the complexity of the reservoir and the complexity of the fluid phases, the current productivity evaluation methods are no longer applicable. In this paper, considering factors such as fracture characteristics, stress sensitivity, and phase distribution, a low-permeability carbonate reservoir gas injection development productivity transient analysis model is established. The results of the study show that the larger the value of permeability damage coefficient, the stronger the curve of the production curve will bend toward the pressure axis. This is because the larger the value of permeability damage coefficient, the more severe the stress sensitivity of the formation is, which shows that rock deformation has an important impact on production. When two phases appear at the bottom of the well, the seepage resistance increases due to the two-phase flow, which in turn causes the productivity of a single well to rapidly decrease. With the decrease of bottom hole pressure, this resistance will increase significantly and the productivity of a single well will decline rapidly.

The Mechanism of Flue Gas Injection for Enhanced Light Oil Recovery

2004 ◽  
Vol 126 (2) ◽  
pp. 119-124 ◽  
Author(s):  
O. S. Shokoya ◽  
S. A. (Raj) Mehta ◽  
R. G. Moore ◽  
B. B. Maini ◽  
M. Pooladi-Darvish ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Flue Gas ◽  
Gas Injection ◽  
Cost Effective ◽  
Air Injection ◽  
Oil Reservoirs ◽  
Flue Gases ◽  
Low Permeability ◽  
Light Oil ◽  
Light Oil Reservoirs

Flue gas injection into light oil reservoirs could be a cost-effective gas displacement method for enhanced oil recovery, especially in low porosity and low permeability reservoirs. The flue gas could be generated in situ as obtained from the spontaneous ignition of oil when air is injected into a high temperature reservoir, or injected directly into the reservoir from some surface source. When operating at high pressures commonly found in deep light oil reservoirs, the flue gas may become miscible or near–miscible with the reservoir oil, thereby displacing it more efficiently than an immiscible gas flood. Some successful high pressure air injection (HPAI) projects have been reported in low permeability and low porosity light oil reservoirs. Spontaneous oil ignition was reported in some of these projects, at least from laboratory experiments; however, the mechanism by which the generated flue gas displaces the oil has not been discussed in clear terms in the literature. An experimental investigation was carried out to study the mechanism by which flue gases displace light oil at a reservoir temperature of 116°C and typical reservoir pressures ranging from 27.63 MPa to 46.06 MPa. The results showed that the flue gases displaced the oil in a forward contacting process resembling a combined vaporizing and condensing multi-contact gas drive mechanism. The flue gases also became near-miscible with the oil at elevated pressures, an indication that high pressure flue gas (or air) injection is a cost-effective process for enhanced recovery of light oils, compared to rich gas or water injection, with the potential of sequestering carbon dioxide, a greenhouse gas.

Pilot Project Evaluating WAG Efficiency for Carbonate Reservoir in Eastern Siberia

2021 ◽  
Author(s):  
Valentina Zharko ◽  
Dmitriy Burdakov
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Oil Production ◽  
Pilot Project ◽  
Carbonate Reservoir ◽  
Recovery Factor ◽  
Eastern Siberia ◽  
Water Cut ◽  
Wag Injection ◽  
Injection Rates

Abstract The paper presents the results of a pilot project implementing WAG injection at the oilfield with carbonate reservoir, characterized by low efficiency of traditional waterflooding. The objective of the pilot project was to evaluate the efficiency of this enhanced oil recovery method for conditions of the specific oil field. For the initial introduction of WAG, an area of the reservoir with minimal potential risks has been identified. During the test injections of water and gas, production parameters were monitored, including the oil production rates of the reacting wells and the water and gas injection rates of injection wells, the change in the density and composition of the produced fluids. With first positive results, the pilot area of the reservoir was expanded. In accordance with the responses of the producing wells to the injection of displacing agents, the injection rates were adjusted, and the production intensified, with the aim of maximizing the effect of WAG. The results obtained in practice were reproduced in the simulation model sector in order to obtain a project curve characterizing an increase in oil recovery due to water-alternating gas injection. Practical results obtained during pilot testing of the technology show that the injection of gas and water alternately can reduce the water cut of the reacting wells and increase overall oil production, providing more efficient displacement compared to traditional waterflooding. The use of WAG after the waterflooding provides an increase in oil recovery and a decrease in residual oil saturation. The water cut of the produced liquid decreased from 98% to 80%, an increase in oil production rate of 100 tons/day was obtained. The increase in the oil recovery factor is estimated at approximately 7.5% at gas injection of 1.5 hydrocarbon pore volumes. Based on the received results, the displacement characteristic was constructed. Methods for monitoring the effectiveness of WAG have been determined, and studies are planned to be carried out when designing a full-scale WAG project at the field. This project is the first pilot project in Russia implementing WAG injection in a field with a carbonate reservoir. During the pilot project, the technical feasibility of implementing this EOR method was confirmed, as well as its efficiency in terms of increasing the oil recovery factor for the conditions of the carbonate reservoir of Eastern Siberia, characterized by high water cut and low values of oil displacement coefficients during waterflooding.

Injectivity and Propagation of Sulfonated Acrylamide-Based Copolymers in Low Permeability Carbonate Reservoir Cores in Harsh Salinity and Temperature Conditions : Challenges and Learnings from a Middle East Onshore Case Study

2021 ◽  
Author(s):  
Nicolas Gaillard ◽  
Matthieu Olivaud ◽  
Alain Zaitoun ◽  
Mahmoud Ould-Metidji ◽  
Guillaume Dupuis ◽  
...  
Keyword(s):  
Middle East ◽  
Polymer Solutions ◽  
Carbonate Reservoir ◽  
Core Material ◽  
Low Permeability ◽  
The Core ◽  
Reservoir Conditions ◽  
Carbonate Cores ◽  
The Impact ◽  
Mobility Reduction

Abstract Polymer flooding is one of the most mature EOR technology applied successfully in a broad range of reservoir conditions. The last developments made in polymer chemistries allowed pushing the boundaries of applicability towards higher temperature and salinity carbonate reservoirs. Specifically designed sulfonated acrylamide-based copolymers (SPAM) have been proven to be stable for more than one year at 120°C and are the best candidates to comply with Middle East carbonate reservoir conditions. Numerous studies have shown good injectivity and propagation properties of SPAM in carbonate cores with permeabilities ranging from 70 to 150 mD in presence of oil. This study aims at providing new insights on the propagation of SPAM in carbonate reservoir cores having permeabilities ranging between 10 and 40 mD. Polymer screening was performed in the conditions of ADNOC onshore carbonate reservoir using a 260 g/L TDS synthetic formation brine together with oil and core material from the reservoir. All the experiments were performed at residual oil saturation (Sor). The experimental approach aimed at reproducing the transport of the polymer entering the reservoir from the sand face up to a certain depth. Three reservoir coreflood experiments were performed in series at increasing temperatures and decreasing rates to mimic the progression of the polymer in the reservoir with a radial velocity profile. A polymer solution at 2000 ppm was injected in the first core at 100 mL/h and 40°C. Effluents were collected and injected in the second core at 20 mL/h and 70°C. Effluents were collected again and injected in the third core at 4 mL/h and 120°C. A further innovative approach using reservoir minicores (6 mm length disks) was also implemented to screen the impact of different parameters such as Sor, molecular weight and prefiltration step on the injectivity of the polymer solutions. According to minicores data, shearing of the polymer should help to ensure good propagation and avoid pressure build-up at the core inlet. This result was confirmed through an injection in a larger core at Sor and at 120°C. When comparing the injection of sheared and unsheared polymer at the same concentration, core inlet impairment was suppressed with the sheared polymer and the same range of mobility reduction (Rm) was achieved in the internal section of the core although viscosity was lower for the sheared polymer. Such result indicates that shearing is an efficient way to improve injectivity while maximizing the mobility reduction by suppressing the loss of product by filtration/retention at the core inlet. This paper gives new insights concerning SPAM rheology in low permeability carbonate cores. Additionally, it provides an innovative and easier approach for screening polymer solutions to anticipate their propagation in more advanced coreflooding experiments.

Sign in / Sign up

Export Citation Format

Share Document