Effect of Reservoir Fluid Type on the Stimulation of Carbonate Reservoirs Using Chelating Agents

2011 ◽  
Author(s):  
Mohamed Ahmednasreldin Mahmoud ◽  
Hisham A. Nasr-El-Din ◽  
Corine DeWolf ◽  
Alan Alex
Keyword(s):  
Chelating Agents ◽  
Carbonate Reservoirs ◽  
Fluid Type ◽  
Reservoir Fluid ◽  
Stimulation Of

Effective Stimulation of Carbonate Reservoirs around the World by Creating Multiple Drainage Holes

2008 ◽  
Author(s):  
Ricardo Salomao Aboud ◽  
Jose Daniel Diaz ◽  
Alfredo Mendez ◽  
Leonard John Kalfayan ◽  
Lance Nigel Portman ◽  
...  
Keyword(s):  
Carbonate Reservoirs ◽  
The World ◽  
Stimulation Of

Effective Stimulation of Very Thick, Layered Carbonate Reservoirs Without the Use of Mechanical Isolation

2009 ◽  
Author(s):  
Chris E. Shuchart ◽  
Shalawn Jackson ◽  
Janette Mendez-Santiago ◽  
Nancy Hyangsil Choi ◽  
John K. Montgomery ◽  
...  
Keyword(s):  
Carbonate Reservoirs ◽  
Mechanical Isolation ◽  
Stimulation Of

The New Flow Control Devices Autonomously Controlling the Performance of Matrix Acid Stimulation Operations in Carbonate Reservoirs

2021 ◽  
Author(s):  
Mojtaba Moradi ◽  
Michael R Konopczynski
Keyword(s):  
Flow Control ◽  
Dynamic Change ◽  
Injection Rate ◽  
Control Flow ◽  
Carbonate Reservoir ◽  
Operating Conditions ◽  
Carbonate Reservoirs ◽  
High Permeability ◽  
The Impact ◽  
Stimulation Of

Abstract Matrix acidizing is a common but complex stimulation treatment that could significantly improve production/injection rate, particularly in carbonate reservoirs. However, the desired improvement in all zones of the well by such operation may not be achieved due to existing and/or developing reservoir heterogeneity. This paper describes how a new flow control device (FCD) previously used to control water injection in long horizontal wells can also be used to improve the conformance of acid stimulation in carbonate reservoirs. Acid stimulation of a carbonate reservoir is a positive feedback process. Acid preferentially takes the least resistant path, an area with higher permeability or low skin. Once acid reacts with the formation, the injectivity in that zone increases, resulting in further preferential injection in the stimulated zone. Over-treating a high permeability zone results in poor distribution of acid to low permeability zones. Mechanical, chemical or foam diversions have been used to improve stimulation conformance along the wellbore, however, they may fail in carbonate reservoirs with natural fractures where fracture injectivity dominates the stimulation process. A new FCD has been developed to autonomously control flow and provide mechanical diversion during matrix stimulation. Once a predefined upper limit flowrate is reached at a zone, the valve autonomously closes. This eliminates the impact of thief zone on acid injection conformance and maintains a prescribed acid distribution. Like other FCDs, this device is installed in several compartments in the wells. The device has two operating conditions, one, as a passive outflow control valve, and two, as a barrier when the flow rate through the valve exceeds a designed limit, analogous to an electrical circuit breaker. Once a zone has been sufficiently stimulated by the acid and the injection rate in that zone exceeds the device trip point, the device in that zone closes and restricts further stimulation. Acid can then flow to and stimulate other zones This process can be repeated later in well life to re-stimulate zones. This performance enables the operators to minimise the impacts of high permeability zones on the acid conformance and to autonomously react to a dynamic change in reservoirs properties, specifically the growth of wormholes. The device can be installed as part of lower completions in both injection and production wells. It can be retrofitted in existing completions or be used in a retrievable completion. This technology allows repeat stimulation of carbonate reservoirs, providing mechanical diversion without the need for coiled tubing or other complex intervention. This paper will briefly present an overview of the device performance, flow loop testing and some results from numerical modelling. The paper also discusses the completion design workflow in carbonates reservoirs.

Foam Acid Treatment - The Key to Stimulation of Carbonate Reservoirs in Depleted Oil Fields of the Samara Region (Russian)

2017 ◽  
Author(s):  
Alexander Letichevskiy ◽  
Alexey Nikitin ◽  
Alexey Parfenov ◽  
Vitaliy Makarenko ◽  
Ilya Lavrov ◽  
...  
Keyword(s):  
Acid Treatment ◽  
Carbonate Reservoirs ◽  
Oil Fields ◽  
Stimulation Of

Dynamic Formation Evaluation to Reduce Uncertainty and Confirm Completed Intervals in Brown Fields

2021 ◽  
Author(s):  
Muhamad Aizat Kamaruddin ◽  
Ayham Ashqar ◽  
Muhammad Haniff Suhaimi ◽  
Fairus Azwardy Salleh
Keyword(s):  
Real Time ◽  
Optical Sensors ◽  
Sensor Technology ◽  
Innovative Technology ◽  
Fluid Type ◽  
Formation Evaluation ◽  
Reservoir Fluid ◽  
Logging While Drilling ◽  
Dynamic Formation

Abstract Uncertainties in fluid typing and contacts within Sarawak Offshore brown field required a real time decision. To enhance reservoir fluid characterisation and confirm reservoir connectivity prior to well final total depth (TD). Fluid typing while drilling was selected to assure the completion strategy and ascertain the fluvial reservoir petrophysical interpretation. Benefiting from low invasion, Logging While Drilling (LWD) sampling fitted with state of ART advanced spectroscopy sensors were deployed. Pressures and samples were collected. The well was drilled using synthetic base mud. Conventional logging while drilling tool string in addition to sampling tool that is equipped with advanced sensor technology were deployed. While drilling real time formation evaluation allowed selecting the zones of interest, while fluid typing was confirmed using continually monitored fluids pump out via multiple advanced sensors, contamination, and reservoir fluid properties were assessed while pumping. Pressure and sampling were performed in drilling mode to minimise reservoir damage, and optimise rig time, additionally sampling while drilling was performed under circulation conditions. Pressures were collected first followed by sampling. High success in collecting pressure points with a reliable fluid gradient that indicated a virgin reservoir allowed the selection of best completion strategy without jeopardising reserves, and reduced rig time. Total of seven samples from 3 different reservoirs, four oil, and three formation water. High quality samples were collected. The dynamic formation evaluation supported by while drilling sampling confirmed the reservoir fluid type and successfully discovered 39ft of oil net pay. Reservoir was completed as an oil producer. The Optical spectroscopy measurements allowed in situ fluid typing for the quick decision making. The use of advanced optical sensors allowed the sample collection and gave initial assessment on reservoir fluids properties, as a result cost saving due to eliminating the need for additional Drill Stem Test (DST) run to confirm the fluid type. Sample and formation pressures has confirmed reservoir lateral continuity in the vicinity of the field. The reservoir developed as thick and blocky sandstone. Collected sample confirmed the low contamination levels. Continuous circulation mitigated sticking and potential well-control risks. This is the first time in surrounding area, advanced optical sensors are used to aid LWD sampling and to finalize the fluid identification. The innovative technology allowed the collection of low contamination. The real-time in-situ fluid analysis measurement allowed critical decisions to be made real time, consequently reducing rig downtime. Reliable analysis of fluid type identification removed the need for additional run/service like DST etc.

Identifying Fluid Type and Contacts in Carbonate Reservoirs

2007 ◽  
Author(s):  
H.-Y. Tseng ◽  
R.J. Pottorf ◽  
D. Mardon ◽  
P.J. Mankiewicz
Keyword(s):  
Carbonate Reservoirs ◽  
Fluid Type

Chelating-Agent Enhanced Oil Recovery for Sandstone and Carbonate Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (03) ◽  
pp. 483-495 ◽  
Author(s):  
M. A. Mahmoud ◽  
K. Z. Abdelgawad
Keyword(s):  
Zeta Potential ◽  
Oil Recovery ◽  
Chelating Agents ◽  
Water Injection ◽  
Chelating Agent ◽  
Carbonate Reservoirs ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Core Permeability

Summary Recently low-salinity waterflooding was introduced as an effective enhanced-oil-recovery (EOR) method in sandstone and carbonate reservoirs. The recovery mechanisms that use low-salinity-water injection are still debatable. The suggested possible mechanisms are: wettability alteration, interfacial-tension (IFT) reduction, multi-ion exchange, and rock dissolution. In this paper, we introduce a new chemical EOR method for sandstone and carbonate reservoirs that will give better recovery than the low-salinity-water injection without treating or diluting seawater. In this study, we introduce a new chemical EOR method that uses chelating agents such as ethylenediaminetetraacetic acid (EDTA), hydroxyethylethylenediaminetriacetic acid (HEDTA), and diethylenetriaminepentaacetic acid (DTPA) at high pH values. This is the first time for use of chelating agents as standalone EOR fluids. Coreflood experiments, interfacial and surface tensions, and zeta-potential measurements are performed with DTPA, EDTA, and HEDTA chelating agents. The chelating-agent concentrations used in the study were prepared by diluting the initial concentration of 40 wt% with seawater and injecting it into Berea-sandstone and Indiana-limestone cores of a 6-in. length and a 1.5-in. diameter saturated with crude oil. The coreflooding experiments were performed at 100°C and a 1,000-psi backpressure. Low-salinity-water and seawater injections caused damage to the reservoir because of the calcium sulfate scale deposition during the flooding process. The newly introduced EOR method did not cause calcium sulfate precipitation, and the core permeability was not affected. The core permeability was measured after the flooding process, and the final permeability was higher than the initial permeability in the case of chelating-agent injection. The coreflooding effluent was analyzed for cations with the inductively coupled plasma (ICP) spectroscopy to explain the dissolution-recovery mechanism. The effect of iron minerals on the rock-surface charge was investigated through the measurements of zeta potential for different rocks containing different iron minerals. HEDTA and EDTA chelating agents at 5 wt% concentration prepared in seawater were able to recover more than 20% oil from the initial oil in place from sandstone and carbonate cores. ICP measurements supported the rock-dissolution mechanism because the calcium, magnesium, and iron concentrations in the effluent samples were more than those in the injected fluids. The IFT-reduction mechanism was confirmed by the low IFT values obtained in the case of chelating agents. The type and concentration of chelating agents affected the IFT value. Higher concentrations yielded lower IFT values because of the increase in carboxylic-group concentration. We found that the high-pH chelating agents increased the negative value of zeta potential, which will change the rock toward more water-wet.

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