Green Well Stimulation Fluids for Enhanced Oil Recovery from Tight Sand Formations: Field Wide 70+ Wells Study Over 4 Years

2021 ◽  
Author(s):  
Martin Shumway ◽  
Ryan McGonagle ◽  
Anthony Nerris ◽  
Janaina I.S. Aguiar ◽  
Amir Mahmoudkhani ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Cost Effective ◽  
Field Trials ◽  
Lessons Learned ◽  
Formation Damage ◽  
Well Stimulation ◽  
Tight Formations ◽  
History Of ◽  
Organic Deposits

Abstract Legacy oil production from Appalachian basin has been in a decline mode since 2013. With more than 80% of wells producing less than 15 bbl/day, there is a growing interest in economically and environmentally viable options for well stimulation treatments. Analysis of formation mineralogy and reservoir fluids along with history of well interventions indicated formation damage in many wells due precipitation of organics and a change in wettability being partially responsible for production decline rates in excess of forecasts. The development and properties of a novel cost-effective biosurfactant based well-stimulation fluid are described here along lessons learned from several field trials in wells completed in the Upper Devonian Bradford Group. This group of 74 wells, completed in siltstone and sandstone reservoirs were presenting more than 12 well failures annually across the field, which was attributed to the accumulation of organic deposits in the tubulars. Based on these cases, batch stimulation treatments using a novel fluid comprising biosurfactants were proposed and implemented field wide. The treatments effectively removed organic deposits, changed formation wettability from oil to water wet and resulted in a sustained oil production increase. Well failures were significantly reduced as a result of this program and the group of 74 wells did not have a paraffin-related well failure for 18 months. Results from this program demonstrates the efficiency of the green well stimulation fluids in mitigating formation damage, reducing organics deposition and in increasing oil production as a promising method to stimulate tight formations.

scholarly journals Application of an Oil-Displacing Composition for Increasing Flow Rate of Low Producing High-Viscosity Oil Wells of the Usinskoye Oil Field

2016 ◽  
Vol 18 (2) ◽  
pp. 133
Author(s):  
L.K. Altunina ◽  
I.V. Kuvshinov ◽  
V.A. Kuvshinov ◽  
V.S. Ovsyannikova ◽  
D.I. Chuykina ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
High Viscosity ◽  
Oil Field ◽  
Thermal Methods ◽  
Cold Stimulation ◽  
Well Production ◽  
Well Stimulation ◽  
High Viscosity Oil ◽  
Stimulation Of

The results of a pilot application of a chemical composition for enhanced oil recovery developed at the IPC SB RAS are presented. The EOR-composition was tested in 2014 at the Permian-Carboniferous heavy oil deposit at the Usinskoye oil field. It is very effective for an increase in oil production rate and decrease in water cuttings of well production. In terms of the additionally produced oil, the resulting effect is up to 800 tons per well and its duration is up to 6 months. The application of technologies of low-productivity-well stimulation using the oil-displacing IKhNPRO system with controlled viscosity and alkalinity is thought to be promising. This composition is proposed for the cold’ stimulation of high-viscosity oil production as an alternative to thermal methods.

scholarly journals USE OF ELECTROTREATMENT METHOD FOR OIL RECOVERY ENHANCEMENT

2015 ◽  
pp. 67-73 ◽  
Author(s):  
O. V. Smirnov ◽  
A. E. Kozyaruk ◽  
K. V. Kuskov ◽  
A. L. Portnyagin ◽  
A. V. Saphonov
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Well Stimulation ◽  
Viscous Oil

The paper considers the issues of oil production enhancement through applying methods of well stimulation including the wells producing viscous oil, in particular various methods of electrotreatment.

Improving Oil Recovery Through Fracture Injection and Production of Multiple Fractured Horizontal Wells

2020 ◽  
Vol 142 (5) ◽  
Author(s):  
Youwei He ◽  
Shiqing Cheng ◽  
Zhe Sun ◽  
Zhi Chai ◽  
Zhenhua Rui
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Horizontal Wells ◽  
Co2 Injection ◽  
Production Rates ◽  
Well Production ◽  
Well Completion ◽  
Tight Formations ◽  
Fractured Horizontal Wells ◽  
The Impact

Abstract Well production rates decline quickly in the tight reservoirs, and enhanced oil recovery (EOR) is needed to increase productivity. Conventional flooding from adjacent wells is inefficient in the tight formations, and Huff-n-Puff also fails to achieve the expected productivity. This paper investigates the feasibility of the inter-fracture injection and production (IFIP) method to increase oil production rates of horizontal wells. Three multi-fractured horizontal wells (MFHWs) are included in a cluster well. The fractures with even and odd indexes are assigned to be injection fractures (IFs) and recovery fractures (RFs). The injection/production schedule includes synchronous inter-fracture injection and production (s-IFIP) and asynchronous inter-fracture injection and production (a-IFIP). The production performances of three MFHWs are compared by using four different recovery approaches based on numerical simulation. Although the number of RFs is reduced by about 50% for s-IFIP and a-IFIP, they achieve much higher oil rates than depletion and CO2 Huff-n-Puff. The sensitivity analysis is performed to investigate the impact of parameters on IFIP. The spacing between IFs and RFs, CO2 injection rates, and connectivity of fracture networks affect oil production significantly, followed by the length of RFs, well spacing among MFHWs, and the length of IFs. The suggested well completion scheme for the IFIP methods is presented. This work discusses the ability of the IFIP method in enhancing the oil production of MFHWs.

Telemedicine: The art of innovative technology in family medicine

2020 ◽  
Vol 55 (5) ◽  
pp. 341-348
Author(s):  
Julia Jenkins ◽  
Oliver Oyama
Keyword(s):  
Family Medicine ◽  
Healthcare Delivery ◽  
High Standard ◽  
Cost Effective ◽  
Lessons Learned ◽  
Innovative Technology ◽  
Patient Centered ◽  
Centered Care ◽  
History Of ◽  
Healthcare Innovation

Technology in medicine has been rapidly evolving over the past decade, greatly improving the quality and types of services providers can offer to patients. Physicians in training are eager to embrace these novel innovations, and medical school and residency educators strive to offer learning experiences of a high standard that are relevant. One example of an emerging healthcare innovation is telemedicine, which permits the provision of medical care to patients away from clinics and hospitals, bringing patient-centered care to the patient. It has proven to be cost-effective, improve health outcomes, and enhance patient satisfaction. This article describes the development and structure of our family medicine residency program’s telemedicine curriculum, first created in 2016 in response to the growing demand for this type of healthcare delivery model. There is discussion about the history of telemedicine, and about what contributed to its growth. A timeline of the steps taken to create our new telemedicine residency curriculum is reviewed, along with the key components that contributed to its success. The Lessons Learned section provides other educators insight into the strengths and opportunities revealed during the creation of the curriculum, and guidance on how the curriculum could be further enhanced.

Enhancing Oil Recovery With Bottom Water Drainage Completion

2014 ◽  
Vol 136 (4) ◽  
Author(s):  
Ephim Shirman ◽  
Andrew K. Wojtanowicz ◽  
Hilal Kurban
Keyword(s):  
Production Rate ◽  
Oil Recovery ◽  
Oil Production ◽  
Fold Increase ◽  
Recovery Process ◽  
Field Trials ◽  
Experimental Results ◽  
Water Drainage ◽  
Performance Study ◽  
Time Required

Field trials and physical modeling of wells with downhole water sink (DWS) completions have demonstrated controlled water coning and increased oil production rate. However, no field trials were long enough to show DWS potential in improving of oil recovery in comparison with conventional wells. Presented here are theoretical and experimental results from a DWS recovery performance study. The recovery study involved experiments with a physical model and computer simulations. The experimental results reveal that DWS dramatically accelerates the recovery process; a fivefold increase of the oil production rate was reached by adjusting the water drainage rate at the bottom completion. The results also show a 70% increase of oil recovery; from 0.52 to 0.88 for conventional and DWS completions, respectively. The computer-simulated experiments with commercial reservoir simulator demonstrate progressive improvement of recovery with downhole water drainage from 0.61 to 0.79 with no drainage and maximum drainage, respectively—a 24% increase of recovery factor, and a fivefold reduction of the time required to reach the limiting value of water cut, 0.98. However, the accelerated recovery process with DWS requires a substantial, up to 3.5-fold, increase of total water production. The simulation experiments also show that the main advantage of using DWS is its flexibility in controlling the recovery process. For conventional completions, recovery could be slightly increased by reducing production rates and largely increasing production times. For DWS, a combination of the top and bottom rates could be optimized for maximum recovery and minimum production time.

Batch Production: A Success Story to Improve Oil Production in Mature Fields in Medco E&P, South Sumatera

2021 ◽  
Author(s):  
N. S. Elthaf
Keyword(s):  
Oil Recovery ◽  
Selection Process ◽  
Cost Effective ◽  
Production Method ◽  
Reservoir Pressure ◽  
Batch Production ◽  
Recovery Potential ◽  
Well Stimulation ◽  
Long Time ◽  
Pressure Increment

X and Y fields are mature fields with almost 400 wells have been drilled since 1996. Many wells have been shut-in for a long time due to producing below economical limit of 10 BOPD. Several reasons are due to depleted reservoir pressure, watered out, and low reservoir quality. Long shut-in time allows the reservoir pressure to build up and improve. On the other side, good waterflood and pressure maintenance efforts also improved the reservoir pressure and oil recovery potential. Many wells become potential for reactivation. In 2018, 5 (five) wells were reactivated after a long period of shut-in. However, the initiatives were not entirely effective due to lack of established method for candidates selection and prioritization applied. Not all wells can be monitored and reviewed thus resulting in lacking of reactivation candidates. In 2019, a more comprehensive method named “Batch Production” is introduced. It is an end-to-end selection process which consists of 5 (five) lenses: well screening, reservoir aspect review, operational aspect review, prioritization, and execution and monitoring. After implementing “Batch Production” method in 2019, we successfully reactivated 35 (thirty five) wells in 2019 – 2020 with total initial gain of 1062 BOPD, which are significantly higher than 2018 result of 5 (five) wells with 184 BOPD gain. Telisa reservoir has higher initial oil gain compared to Baturaja reservoir which were mostly driven by reservoir pressure increment. This result proves how “Batch Production” method is effective and covers all the important aspects in well reactivation. It also helps the operation team by streamlining the process of reactivating a well. No additional cost such as rig intervention or well stimulation is needed in this method, making this initiative as cost-effective yet very profitable for mature fields.

Reintroduction of Carbon Dioxide Supply from Central to South Trinidad via Pipeline – Perspectives and Possibilities for Using Present System

2014 ◽  
Author(s):  
S.A.. A. Butcher ◽  
J.. Isaac ◽  
C.. Frontin-De Peaza
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Waste Product ◽  
Cost Effective ◽  
Lessons Learned ◽  
Pipeline System ◽  
Present System ◽  
Pipeline Network ◽  
Integrity Assessment ◽  
Co2 Eor

Abstract Increasing oil production in Trinidad and Tobago (T&T) by means such as Enhanced Oil Recovery (EOR) may be a more cost effective and less risky pathway, when compared to the drilling of exploration and appraisal wells. This is because the fields and reservoirs that would be considered for EOR projects are generally in an advanced state of delineation and there has been experience derived from production data for some time. Considering the scope/applicability of carbon dioxide EOR (CO2-EOR), the revitalization of such projects in T&T would aid in extending the use of CO2 to another purpose, given its useful properties and behaviour, before being emitted to the atmosphere. Five CO2 EOR pilot projects were implemented in South Trinidad, starting in the early 1970's. At that time, as it is now, Trinidad had abundant CO2 available as a waste product from the ammonia manufacturing operations at the Point Lisas Industrial Estate (PLIE), Central Trinidad. At present, consideration is being made for the reintroduction of CO2 pipeline transport, directed to suitable EOR candidate sites mainly in South Trinidad, focusing once more on CO2 sourced from the PLIE. Det Norske Veritas (DNV) has introduced a Recommended Practice (RP) on the Design and Operation of CO2 Pipelines (RP-J202), incorporating lessons learned from existing CO2 pipelines around the world. This RP provides guidance for managing risks and uncertainties during the lifecycle of a CO2 pipeline, including design, testing, inspection, operation, maintenance, and de-commissioning. This paper will use DNV-RP-J202 to present a guiding framework for the possible re-qualification of sections of the existing CO2 pipeline network in Trinidad for the reintroduction of safe and efficient CO2 pipeline operations. The re-qualification process entails the following steps: Initiation, Integrity Assessment, Hydraulic Analysis, Safety Evaluation, Premises, Re-assessment, Modification Alternative(s), Documentation and Implementation. On completion of the re-qualification process, the majority of the pipeline system may not be acceptable for reintroduction of CO2. Options for consideration can be an adjustment of the pipeline routes where sections of pipeline network are not in acceptable condition, or the development of a completely new pipeline network and/or new routes.

scholarly journals Oil production and reservoir damage during miscible CO2 injection

2020 ◽  
Vol 39 (1) ◽  
pp. 22-28 ◽  
Author(s):  
Qian Wang ◽  
Piroska Lorinczi ◽  
Paul W. J. Glover
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Control Measures ◽  
Co2 Injection ◽  
Formation Damage ◽  
Core Flooding ◽  
Asphaltene Precipitation ◽  
Pore Throat ◽  
Oil Distribution ◽  
Inorganic Precipitation

The blockage and alteration of wettability in reservoirs caused by asphaltene deposits are problems that contribute to poor oil recovery performance during carbon dioxide (CO2) injection. Oil production and reservoir damage are both controlled by macroscopic interlayer heterogeneity and microscopic pore-throat structure and may be optimized by the choice of flooding method. In this work, the residual oil distribution and the permeability decline caused by organic and inorganic precipitation after miscible CO2 flooding and water-alternating-CO2 (CO2-WAG) flooding have been studied by carrying out core-flooding experiments on a model heterogeneous three-layer reservoir. For CO2, flooding experimental results indicate that the low-permeability layers retain a large oil production potential even in the late stages of production, while the permeability decline due to formation damage is larger in the high-permeability layer. We found that CO2-WAG can reduce the influence of heterogeneity on the oil production, but it results in more serious reservoir damage, with permeability decline caused by CO2–brine–rock interactions becoming significant. In addition, miscible CO2 flooding has been carried out for rocks with similar permeabilities but different wettabilities and different pore-throat microstructures in order to study the effects of wettability and pore-throat microstructure on formation damage. Reservoir rocks with smaller pore-throat sizes and more heterogeneous pore-throat microstructures were found to be more sensitive to asphaltene precipitation, with corresponding lower oil recovery and greater decreases in permeability. However, it was found that the degree of water wetness for cores with larger, more connected pore-throat microstructures became weaker due to asphaltene precipitation to pore surfaces. Decreasing the degree of water wetness was found to be exacerbated by increases in the sweep volume of injected CO2 that arise from cores with larger and better connected pore throats. Erosion of water wetness is a disadvantage for enhanced oil recovery operations as asphaltene precipitation prevention and control measures become more necessary.

scholarly journals Selection of effective methods of increasing oil recovery in dealed fields based on retrospective analysis

2021 ◽  
Vol 6 (1(62)) ◽  
pp. 48-51
Author(s):  
Volodymyr Doroshenko ◽  
Oleksandr Titlov
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Polymer Flooding ◽  
Economic Effects ◽  
Methods Development ◽  
History Of ◽  
Development Processes ◽  
Development Analysis ◽  
Water Gas ◽  
Oilfield Development

The object of research is methods of increasing oil recovery in «old», depleted oilfields. One of the main tasks of the oil-extracting industry in any country in the world was and still is ensuring the project level of oil production at the maximum possible coefficient of its extraction from the subsoil. In this case it is extremely important to study and use technological methods and means of acquired experience in oilfield development. The paper considers the historical aspects of the development of stabilization and oil recovery methods from 1770s to the present day on the example of Ukrainian oilfields. In parallel with the history of the implementation of methods, their physical and technological content and conditions of application are discussed. Of all the methods used to increase the level of oil production, the most effective ones, which have found application at certain stages of the Ukrainian oilfields’ development, are considered. This is, first of all, a vacuum process, areal flooding, cyclic flooding, gas and water-gas repression, injection of surfactants, surfactant polymer-containing systems, polymer flooding, horizontal branched drilling. The methods development analysis is considered against the background of their geological and industrial acceptability and obtaining technical and economic effects. Based on the results of the study, a group of methods has been identified. These methods are advised to apply in geological and industrial conditions, similar to those described, which should ensure the expected efficiency. Undoubtedly, along with this, it is advisable to use the methods of mathematical modeling of oilfield development processes. Proposals are formulated on the conditions and principles of applying the methods under consideration in order to improve the systems for the development of oilfields. It has been established that the most acceptable methods of increasing oil recovery in depleted oilfields are the injection of surfactant solutions both independently and together with an aqueous solution of polyacrylamide, creation of gas-water repression and polymer flooding, in which preference is given to AN132SH and AN125SH reagents of FLOPAAM S series from SNF FlOERGEL.

scholarly journals OPTIMIZATION OF SURFACTANT FLOODING ON BJG FIELD USING DYNAMIC PATTERN

PETRO ◽  
2020 ◽  
Vol 9 (2) ◽  
pp. 52
Author(s):  
Ajeng Purna Putri Oktaviani ◽  
Leksono Mucharam
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Real Data ◽  
Cost Effective ◽  
Oil Fields ◽  
Recovery Factor ◽  
Surfactant Flooding ◽  
Spot Pattern ◽  
Dynamic Pattern ◽  
Mature Field

<em>Mature fields, also known as brownfields, are fields that are in a state of declining production or reaching the end of their production lives.  Development of mature oil fields has been, and will increasingly be, an exciting subject (Babadagli, 2007). New studies already discovered innovative ways of finding, developing, and producing hydrocarbons that are efficient and cost-effective and minimize harm to the environment. BJG Field is one of the mature fields which is produced in 1927, one of the efforts for enhancing the production is using waterflood at the beginning of 2001. To increase production further, then we need to conducted studies as an application of the second recovery from BJG Field. The oil recovery factor BJG field can be increased using a surfactant flooding scenario. This research aimed to conduct a study of dynamic pattern surfactant flooding using simulations as applicable for the mature field. The research is expected to obtain an optimum surfactant injection scenario using IMEX and STARS simulator. Simulation is done with real data from the BJG field, and the result has shown the scenario which has the most significant oil production. The highest recovery factor is the chosen scenario. From the results of studies and simulation shown that dynamic pattern inverted five-spot pattern can be used. The increment of oil recovery factor is 32.29% from the waterflood case.</em>

Sign in / Sign up

Export Citation Format

Share Document