Lessons Learned From Applications of a New Organic-Oil-Recovery Method That Activates Resident Microbes

Summary Using a breakthrough process, which does not require microbes to be injected, more than 100 microbial enhanced-oil-recovery (MEOR) treatments were conducted from 2007 to the end of 2010 in oil-producing and water-injection wells in the United States and Canada. On average, these treatments increased oil production by 122%, with an 89% success rate. This paper reviews the MEOR process, reviews the results of the first 100+ treatments, and shares what has been learned from this work. Observations and conclusions include the following: Screening reservoirs is critical to success. Identifying reservoirs where appropriate microbes are present and oil is movable is the key. MEOR can be applied to a wide range of oil gravities. MEOR has been applied successfully to reservoirs with oil gravity as high as 41° API and as low as 16° API. When microbial growth is appropriately controlled, reservoir plugging or formation damage is no longer a risk. Microbes reside in extreme conditions and can be manipulated to perform valuable in-situ "work." MEOR has been applied successfully at reservoir temperatures as high as 200°F and salinities as high as 140,000 ppm total dissolved solids (TDS). MEOR can be applied successfully in dual-porosity reservoirs. A side benefit of applying MEOR is that it can reduce reservoir souring. An oil response is not always observed when treating producing wells. MEOR can be applied to many more reservoirs than thought originallys with little downside risk. This review of more than 100 MEOR well treatments expands the types of reservoirs in which MEOR can be applied successfully. Low-risk and economically attractive treatments can be accomplished when appropriate scientific analysis and laboratory screening are performed before treatments.

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The Triangle "U" Sussex Unit - A Case History Comparing Two Chemical Enhanced Waterflood Methods

SPE Reservoir Evaluation & Engineering ◽

10.2118/53007-pa ◽

1998 ◽

Vol 1 (06) ◽

pp. 545-550 ◽

Cited By ~ 1

Author(s):

J.E. Smith ◽

Dan Larsen

Keyword(s):

Oil Recovery ◽

Water Injection ◽

Rocky Mountain ◽

Water Source ◽

Cationic Polymer ◽

Injection Wells ◽

Recovery Method ◽

Secondary Recovery ◽

Permeable Rock

Summary The Triangle "U" unit is located in Campbell County, Wyoming, in the Powder River basin. The field produces mainly from the Sussex A sandstone, with completions and limited production from the Sussex B. The flood recovered 12.8% original oil in place (OOIP) on primary before the waterflood, which began in March 1981. The Sussex A is relatively tight, with an average permeability of 15 md and porosity of 13.5%. The rock contains swelling and migrating clays, and the initial injection water source was fresh, leading to concerns about long-term injectivity. To stabilize clays, two different processes were applied. Earlier injection wells were treated with a combination of potassium chloride (KCl) and cationic polymer. Later injection wells were treated with potassium hydroxide (KOH). A recent comparison of long-term performance of the two groups of injection wells shows that the wells treated with KOH injected 476,437 bbls/porosity-ft more water than the wells treated with cationic polymer, in 1.4 years less time. This is an 83% increase in cumulative water injection. After KOH, all injection wells were put on a low concentration of imbibition agent to maximize in-depth penetration of water into low permeable rock. Cumulative oil recovery through March 1997 is 36.4% OOIP, compared to the original waterflood projection of 26.6% OOIP. A total of 37.7% pore volume (PV) water has been injected, and the water/oil ratio (WOR) is currently 0.71, for a fairly efficient flood in this tight, dirty sandstone. Introduction The Triangle "U" unit produced 12.8% OOIP on primary before initiation of a waterflood. Several methods of secondary recovery were considered for this reservoir. Gas injection was not feasible because of limited supplies, and micellar injection was too expensive and risky. Waterflood susceptibility testing in cores showed favorable displacement of oil by water, making this the most appropriate secondary recovery method. The waterflood was projected to recover an additional 13.8% OOIP. Polymer flooding was not considered, because the mobility ratio was favorable and the reservoir was relatively tight, with an average permeability of 15 md. There were two basic challenges to waterflooding. First, there was concern that clays would limit injectivity over time. Also, the rock exhibited a permeability variation of 0.65, which could lead to bypassing of recoverable oil as water tended to establish channels through more permeable rock. Clays can exacerbate channeling. SPE 53007 was revised for publication from paper SPE 39937, first presented at the 1998 SPE Rocky Mountain Regional/Low Permeability Reservoirs Symposium, Denver, Colorado, 5-8 April.

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Lessons from Trinidad's CO2 Immiscible Pilot Projects

SPE Reservoir Evaluation & Engineering ◽

10.2118/89364-pa ◽

2005 ◽

Vol 8 (05) ◽

pp. 397-403 ◽

Cited By ~ 12

Author(s):

Lorna J. Mohammed-Singh ◽

Ashok K. Singhal

Keyword(s):

Natural Gas ◽

Oil Recovery ◽

Water Injection ◽

Lessons Learned ◽

Co2 Injection ◽

Efficient Production ◽

Co2 Flooding ◽

Injection Wells ◽

Forest Reserve ◽

Stable Mode

Summary Four immiscible carbon dioxide (CO2) pilot floods were implemented in the Petroleum Co. of Trinidad and Tobago's (Petrotrin's) reservoirs at its Forest Reserve and Oropouche fields, Trinidad, over the period 1973 to 1990. The projects were conducted in a gravity-stable mode after primary, secondary, and tertiary production (after natural-gas and water injection). CO2 was injected into thick sands of variable continuity containing medium-gravity crude (17 to29°API). Production increases were observed in all projects. It is postulated that injected CO2 swelled the oil, reduced viscosity and helped form oil banks that could move more easily under gravity. Oil-production rates and recovery improved as a consequence. In some of the projects, these beneficial effects continued for several years, even after discontinuation of CO2 injection(supply interruptions), with recovery aided by water influx. Interruptions in CO2 supply did not appear to harm incremental oil recovery materially. Channeling was observed at high injection rates and was promoted in reservoirs with low transmissibility. Oil recovery improved as more offtake (production) wells were added downstream of the injection wells. This phenomenon reinforced the importance of optimizing volumetric sweep and of capture during CO2 flooding by judiciously selecting injection and offtake locations. Incremental recovery ranges between2 and 8% of the original oil in place (OOIP), with predicted ultimate recoveries of 4 to 9% of OOIP. Cumulative CO2 use improved with efficient production practices and ranges from 3 to 11 Mcf/bbl to date. Introduction The Forest Reserve and Oropouche fields are located in the southwest peninsula of the island of Trinidad, as shown in Fig. 1. In 1973, CO2 injection was initiated into a former natural-gas-injection project in Forest Reserve when there was a shortage of natural gas. Three immiscible pilot floods and one cyclic-injection project were later implemented between 1974 and 1986. Another immiscible pilot flood was implemented in 1990 in the Oropouche field. These projects were implemented in a "poor boy" mode using existing wells and equipment. CO2 is piped 25 miles from an ammonia plant, compressed, and injected into target reservoirs. This paper documents Petrotrin's 30 years of experience1 with CO2 immiscible injection into these projects and presents a comparative analysis of the performance of the four enhanced-oil-recovery (EOR) projects with some immiscible CO2-flood projects from the literature. Results and lessons learned will be used to guide the extension of CO2 injection to other similar reservoirs in the company's operations and to improve the management of existing projects.

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Risk and the Republican National Convention: Application of the Novel COVID-19 Operational Risk Assessment

Disaster Medicine and Public Health Preparedness ◽

10.1017/dmp.2020.499 ◽

2021 ◽

pp. 1-6

Author(s):

David Callaway ◽

Jeff Runge ◽

Lucia Mullen ◽

Lisa Rentz ◽

Kevin Staley ◽

...

Keyword(s):

Risk Assessment ◽

Health Care ◽

Care Delivery ◽

The United States ◽

Lessons Learned ◽

World Health ◽

Local Health ◽

Mass Gathering ◽

Wide Range ◽

National Convention

Abstract The United States Centers for Disease Control and Prevention and the World Health Organization broadly categorize mass gathering events as high risk for amplification of coronavirus disease 2019 (COVID-19) spread in a community due to the nature of respiratory diseases and the transmission dynamics. However, various measures and modifications can be put in place to limit or reduce the risk of further spread of COVID-19 for the mass gathering. During this pandemic, the Johns Hopkins University Center for Health Security produced a risk assessment and mitigation tool for decision-makers to assess SARS-CoV-2 transmission risks that may arise as organizations and businesses hold mass gatherings or increase business operations: The JHU Operational Toolkit for Businesses Considering Reopening or Expanding Operations in COVID-19 (Toolkit). This article describes the deployment of a data-informed, risk-reduction strategy that protects local communities, preserves local health-care capacity, and supports democratic processes through the safe execution of the Republican National Convention in Charlotte, North Carolina. The successful use of the Toolkit and the lessons learned from this experience are applicable in a wide range of public health settings, including school reopening, expansion of public services, and even resumption of health-care delivery.

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The New Generation of Outflow Control Devices Autonomously Controlling the Conformance of Water Injection Well- A Case Study with ADNOC Onshore

10.2118/207647-ms ◽

2021 ◽

Author(s):

Sultan Ibrahim Al Shemaili ◽

Ahmed Mohamed Fawzy ◽

Elamari Assreti ◽

Mohamed El Maghraby ◽

Mojtaba Moradi ◽

...

Keyword(s):

Oil Recovery ◽

Dynamic Properties ◽

Short Circuit ◽

Water Injection ◽

Performance Outcomes ◽

Injection Well ◽

Well Performance ◽

Injection Wells ◽

Horizontal Section ◽

Control Devices

Abstract Several techniques have been applied to improve the water conformance of injection wells to eventually improve field oil recovery. Standalone Passive flow control devices or these devices combined with Sliding sleeves have been successful to improve the conformance in the wells, however, they may fail to provide the required performance in the reservoirs with complex/dynamic properties including propagating/dilating fractures or faults and may also require intervention. This is mainly because the continuously increasing contrast in the injectivity of a section with the feature compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone which ultimately creates short-circuit to the nearby producer wells. The new autonomous injection device overcomes this issue by selectively choking the injection of fluid into the growing fractures crossing the well. Once a predefined upper flowrate limit is reached at the zone, the valves autonomously close. Well A has been injecting water into reservoir B for several years. It has been recognised from the surveys that the well passes through two major faults and the other two features/fractures with huge uncertainty around their properties. The use of the autonomous valve was considered the best solution to control the water conformance in this well. The device initially operates as a normal passive outflow control valve, and if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This provides the advantage of controlling the faults and fractures in case they were highly conductive as compared to other sections of the well and also once these zones are closed, the device enables the fluid to be distributed to other sections of the well, thereby improving the overall injection conformance. A comprehensive study was performed to change the existing dual completion to a single completion and determine the optimum completion design for delivering the targeted rate for the well while taking into account the huge uncertainty around the faults and features properties. The retrofitted completion including 9 joints with Autonomous valves and 5 joints with Bypass ICD valves were installed in the horizontal section of the well in six compartments separated with five swell packers. The completion was installed in mid-2020 and the well has been on the injection since September 2020. The well performance outcomes show that new completion has successfully delivered the target rate. Also, the data from a PLT survey performed in Feb 2021 shows that the valves have successfully minimised the outflow toward the faults and fractures. This allows achieving the optimised well performance autonomously as the impacts of thief zones on the injected fluid conformance is mitigated and a balanced-prescribed injection distribution is maintained. This paper presents the results from one of the early installations of the valves in a water injection well in the Middle East for ADNOC onshore. The paper discusses the applied completion design workflow as well as some field performance and PLT data.

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Investigation of Oil Recovery in Fractured Carbonate Rock by

Energy and Environment Research ◽

10.5539/eer.v6n1p14 ◽

2016 ◽

Vol 6 (1) ◽

pp. 14

Author(s):

H. Karimaie ◽

O. Torsæter

Keyword(s):

Oil Recovery ◽

Gas Injection ◽

Water Injection ◽

Co2 Injection ◽

Recovery Method ◽

Asmari Limestone ◽

Fractured Carbonate ◽

Efficient Recovery ◽

Live Oil ◽

Non Equilibrium

The purpose of the three experiments described in this paper is to investigate the efficiency of secondary andtertiary gas injection in fractured carbonate reservoirs, focusing on the effect of equilibrium gas,re-pressurization and non-equilibrium gas. A weakly water-wet sample from Asmari limestone which is the mainoil producing formation in Iran, was placed vertically in a specially designed core holder surrounded withfracture. The unique feature of the apparatus used in the experiment, is the capability of initializing the samplewith live oil to obtain a homogeneous saturation and create the fracture around it by using a special alloy whichis easily meltable. After initializing the sample, the alloy can be drained from the bottom of the modified coreholder and create the fracture which is filled with live oil and surrounded the sample. Pressure and temperaturewere selected in the experiments to give proper interfacial tensions which have been measured experimentally.Series of secondary and tertiary gas injection were carried out using equilibrium and non-equilibrium gas.Experiments have been performed at different pressures and effect of reduction of interfacial tension werechecked by re-pressurization process. The experiments showed little oil recovery due to water injection whilesignificant amount of oil has been produced due to equilibrium gas injection and re-pressurization. Results alsoreveal that CO2 injection is a very efficient recovery method while injection of C1 can also improve the oilrecovery.

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Polymer gels for controlling water thief zones in injection wells

CT&F - Ciencia Tecnología y Futuro ◽

10.29047/01225383.215 ◽

2012 ◽

Vol 5 (1) ◽

pp. 37-44 ◽

Cited By ~ 3

Author(s):

Gustavo-Adolfo Maya-Toro ◽

Rubén-Hernán Castro-García ◽

Zarith del Pilar Pachón-Contreras. ◽

Jose-Francisco Zapata-Arango

Keyword(s):

Oil Recovery ◽

Water Injection ◽

Injection Wells ◽

Recovery Processes ◽

Injection Water ◽

Secondary Oil Recovery ◽

High Concentrations ◽

Low Efficiency ◽

Hydrolyzed Polyacrylamide ◽

Positive Results

Oil recovery by water injection is the most extended technology in the world for additional recovery, however, formation heterogeneity can turn it into highly inefficient and expensive by channeling injected water. This work presents a chemical option that allows controlling the channeling of important amounts of injection water in specific layers, or portions of layers, which is the main explanation for low efficiency in many secondary oil recovery processes. The core of the stages presented here is using partially hydrolyzed polyacrylamide (HPAM) cross linked with a metallic ion (Cr+3), which, at high concentrations in the injection water (5000 – 20000 ppm), generates a rigid gel in the reservoir that forces the injected water to enter into the formation through upswept zones. The use of the stages presented here is a process that involves from experimental evaluation for the specific reservoir to the field monitoring, and going through a strict control during the well intervention, being this last step an innovation for this kind of treatments. This paper presents field cases that show positive results, besides the details of design, application and monitoring.

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Numerical Simulation of Two-Phase Flows in Heterogeneous Porous Media

TEMA (São Carlos) ◽

10.5540/tema.2020.021.02.339 ◽

2020 ◽

Vol 21 (2) ◽

pp. 339

Author(s):

I. Carneiro ◽

M. Borges ◽

S. Malta

Keyword(s):

Porous Media ◽

Oil Recovery ◽

Flow Behavior ◽

Water Injection ◽

Heterogeneous Porous Media ◽

Flow In Porous Media ◽

High Porosity ◽

Two Phase ◽

Recovery Method ◽

Porosity And Permeability

In this work,we present three-dimensional numerical simulations of water-oil ﬂow in porous media in order to analyze the inﬂuence of the heterogeneities in the porosity and permeability ﬁelds and, mainly, their relationships upon the phenomenon known in the literature as viscous ﬁngering. For this, typical scenarios of heterogeneous reservoirs submitted to water injection (secondary recovery method) are considered. The results show that the porosity heterogeneities have a markable inﬂuence in the ﬂow behavior when the permeability is closely related with porosity, for example, by the Kozeny-Carman (KC) relation.This kind of positive relation leads to a larger oil recovery, as the areas of high permeability(higher ﬂow velocities) are associated with areas of high porosity (higher volume of pores), causing a delay in the breakthrough time. On the other hand, when both ﬁelds (porosity and permeability) are heterogeneous but independent of each other the inﬂuence of the porosity heterogeneities is smaller and may be negligible.

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Ten years of time-lapse seismic on Atlantis Field

The Leading Edge ◽

10.1190/tle40070494.1 ◽

2021 ◽

Vol 40 (7) ◽

pp. 494-501

Author(s):

Jean-Paul van Gestel

Keyword(s):

Waveform Inversion ◽

Water Injection ◽

Main Tool ◽

Time Lapse ◽

Velocity Model ◽

Lessons Learned ◽

Ocean Bottom ◽

Injection Wells ◽

History Match ◽

Business Decisions

In 2019, the fourth ocean-bottom-node survey was acquired over Atlantis Field. This survey was quickly processed to provide useful time-lapse (4D) observations two months after the end of the acquisition. The time-lapse observations were immediately valuable in placing wells, refining final drilling target locations, updating well prioritization, and sequencing production and water-injection wells. These data are indispensable pieces of information that bring geophysicists and reservoir engineers together and focus the conversation on key remaining uncertainties such as fault transmissibilities and drainage areas. Time-lapse observations can confirm the key conceptional models already in place but are even more valuable when they highlight alternative models that have not yet been considered. The lessons learned from the acquisition, processing, analysis, interpretation, and integration of the data are shared. Some of these lessons are reiterations of previous work, but several new lessons originated from the latest 2019 acquisition. This was the first survey in which independent simultaneous sources were successfully deployed to collect a time-lapse survey. This resulted in a much faster and less expensive acquisition. In addition, full-waveform inversion was used as the main tool to update the velocity model, enabling a much faster turnaround in processing. The fast turnaround enabled incorporation of the latest acquisition to better constrain the velocity model update. The updated velocity model was used for the final time-lapse migration. In the integration part, the 4D-assisted history-match workflow was engaged to update the reservoir model history match. All of the upgrades led to an overall faster, less expensive, and better way to incorporate the acquired data in the final business decisions.

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Increasing Efficiency of Field Water Re-Injection during Water-Flooding in Mature Hydrocarbon Reservoirs: A Case Study from the Sava Depression, Northern Croatia

Sustainability ◽

10.3390/su12030786 ◽

2020 ◽

Vol 12 (3) ◽

pp. 786 ◽

Cited By ~ 2

Author(s):

Tomislav Malvić ◽

Josip Ivšinović ◽

Josipa Velić ◽

Jasenka Sremac ◽

Uroš Barudžija

Keyword(s):

Water Injection ◽

Inverse Distance Weighting ◽

Hydrocarbon Reservoirs ◽

Water Flooding ◽

Injection Wells ◽

Weighting Method ◽

Hydrocarbon Production ◽

Recovery Method ◽

Distance Weighting ◽

Inverse Distance

The authors analyse the process of water re-injection in the hydrocarbon reservoirs/fields in the Upper Miocene sandstone reservoirs, located in the western part of the Sava Depression (Croatia). Namely, this is the “A” field with “L” reservoir that currently produces hydrocarbons using a secondary recovery method, i.e., water injection (in fact, re-injection of the field waters). Three regional reservoir variables were analysed: Porosity, permeability and injected water volumes. The quantity of data was small for porosity reservoir “L” and included 25 points; for permeability and injected volumes of water, 10 points each were measured. This study defined selection of mapping algorithms among methods designed for small datasets (fewer than 20 points). Namely, those are inverse distance weighting and nearest and natural neighbourhood. Results were tested using cross-validation and isoline shape recognition, and the inverse distance weighting method is described as the most appropriate approach for mapping permeability and injected volumes in reservoir “L”. Obtained maps made possible the application of the modified geological probability calculation as a tool for prediction of success for future injection (with probability of 0.56). Consequently, it was possible to plan future injection more efficiently, with smaller injected volumes and higher hydrocarbon recovery. Prevention of useless injection, decreasing number of injection wells, saving energy and funds invested in such processes lead to lower environmental impact during the hydrocarbon production.

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Research of Improving Water Injection Effect by Using Active SiO2 Nano-Powder in the Low-Permeability Oilfield

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.92.207 ◽

2010 ◽

Vol 92 ◽

pp. 207-212 ◽

Cited By ~ 14

Author(s):

Ke Liang Wang ◽

Shou Cheng Liang ◽

Cui Cui Wang

Keyword(s):

Oil Recovery ◽

Pore Volume ◽

Water Injection ◽

Field Tests ◽

Injection Pressure ◽

Rock Surface ◽

Low Permeability ◽

Injection Wells ◽

Decompression Rate ◽

Nano Powder

SiO2 nano-powder is a new type of augmented injection agent, has the ability of stronger hydrophobicity and lipophilicity, and can be adsorbed on the rock surface so that it changes the rock wettability. It can expand the pore radius effectively, reduce the flow resistance of injected water in the pores, enhance water permeability, reduce injection pressure and augment injection rate. Using artificial cores which simulated geologic conditions of a certain factory of Daqing oilfield, decompression and augmented injection experiments of SiO2 nano-powder were performed after waterflooding, best injection volume of SiO2 nano-powder under the low-permeability condition was selected. It has shown that SiO2 nano-powder inverted the rock wettability from hydrophilicity to hydrophobicity. Oil recovery was further enhanced after waterflooding. With the injection pore volume increasing, the recovery and decompression rate of SiO2 nano-powder displacement increased gradually. The best injected pore volume and injection concentration is respectively 0.6PV and 0.5%, the corresponding value of EOR is 6.84% and decompression rate is 52.78%. According to the field tests, it is shown that, in the low-permeability oilfield, the augmented injection technology of SiO2 nano-powder could enhance water injectivity of injection wells and reduce injection pressure. Consequently, it is an effective method to resolve injection problems for the low-permeability oilfield.

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