scholarly journals Review of Absorption Oil Content in Water Injection

2020 ◽  
Author(s):  
Aditya Nugraha Ernawan ◽  
Alfi Fachrizal ◽  
Angga Wijaya ◽  
Bima Syahreza ◽  
Muhammad Ridwan Alkhandi ◽  
...  
Keyword(s):  
Oil Content ◽  
Oil And Gas ◽  
Produced Water ◽  
Economic Condition ◽  
Water Injection ◽  
Oil Production ◽  
Injection Well ◽  
Shaly Sand

Implementation of waterflood is with injected pressured water to reservoir to escalation oil production. Produced water is the dominated result from oil and gas mechanism in this world meanwhile 65% of water is injected back to the well for pressure maintenance, 30% for discharge aquifier condition and surface. For shaly sand, produced water usually bring coarse and suspended sand to the surface. Therefore, this sand level is needed to declining to avoid plugging in injection well until certain economic condition.

An Experimental Research on Enhanced Oil Recovery Using Local Polymers

2021 ◽  
Author(s):  
Abiola Oyatobo ◽  
Amalachukwu Muoghalu ◽  
Chinaza Ikeokwu ◽  
Wilson Ekpotu
Keyword(s):  
Enhanced Oil Recovery ◽  
Experimental Research ◽  
Oil Recovery ◽  
Capital Investment ◽  
Oil And Gas ◽  
Produced Water ◽  
Water Injection ◽  
Gum Arabic ◽  
Oil And Gas Industry ◽  
Profile Control

Abstract Ineffective methods of increasing oil recovery have been one of the challenges, whose solutions are constantly sought after in the oil and gas industry as the number of under-produced reservoirs increases daily. Water injection is the most extended technology to increase oil recovery, although excessive water production can pose huge damage ranging from the loss of the well to an increase in cost and capital investment requirement of surface facilities to handle the produced water. To mitigate these challenges and encourage the utilization of local contents, locally produced polymers were used in polymer flooding as an Enhanced Oil Recovery approach to increase the viscosity of the injected fluids for better profile control and reduce cost when compared with foreign polymers as floppan. Hence this experimental research was geared towards increasing the efficiency of oil displacement in sandstone reservoirs using locally sourced polymers in Nigeria and also compared the various polymers for optimum efficiency. Starch, Ewedu, and Gum Arabic were used in flooding an already obtained core samples and comparative analysis of this shows that starch yielded the highest recovery due to higher viscosity value as compared to Ewedu with the lowest mobility ratio to Gum Arabic. Finally, the concentration of Starch or Gum Arabic should be increased for optimum recovery.

Modelling Produced Water Re-Injection Scaling Compability Performance in Matured Hydrocarbon Aquifer, Nigeria

2018 ◽  
Author(s):  
Theophilus A. Fashanu ◽  
Peter O. Idialu ◽  
Kingsley E. Abhulimen
Keyword(s):  
Computational Models ◽  
Produced Water ◽  
Water Injection ◽  
Scaling Limit ◽  
Cross Flow ◽  
Injection Well ◽  
Scaling Effect ◽  
Produce Water ◽  
Water Zone ◽  
Numerical Strategy

Computational models are developed to predict scale formations, compatibility and injection performance of produced water re-injection in mature hydrocarbon aquifer fields. The models are based on a robust numerical strategy that considered representative K-factors to predict correction for injectivity decline profiles. Simulations in COMSOL Multi-physics environment evaluate scaling effect to determine multi-reservoir commingling phenomenon in matured fields. Results demonstrated that geochemical scaling limit feasible and sustainable water injection performance that could impact petroleum recovery. Fracturing out of water zone was also significant near top and bottom interval cross flow of injection well requiring additional pressure of 100 to 200 psi to initiate fracturing. This requirement excluded fracturing in produce water most re-injection fields with attendant scaling effect.

APPLICATION OF NUCLEONIC INSTRUMENTS IN SEPARATOR PROFILING: KUITO FPSO CASE STUDY

2006 ◽  
Vol 46 (1) ◽  
pp. 405
Author(s):  
B. Beinart
Keyword(s):  
Deep Water ◽  
Oil And Gas ◽  
Produced Water ◽  
Single Point ◽  
Oil Production ◽  
Fluid Interface ◽  
Start Up ◽  
Fluid Levels ◽  
Separation Problems

The Kuito field lies in the offshore Cabinda Province, Angola. Kuito was Angola’s first deep-water oil and came on stream in December 1999. Kuito oil is produced via an FPSO. Kuito oil ranges 18–22 API. The FPSO has threephase, horizontal, gravity separation vessels that are used to separate oil and gas from unwanted produced water and solids prior to transportation. The production separators were designed with traditional, single point transmitters for measurement of the fluid interface and overall fluid levels. These were capacitance type instruments mounted inside the vessels in stilling wells.Following production start-up, separation problems began to emerge; these were manifested in numerous process upsets and shutdowns. Kuito oil can form emulsions quickly, and calcium naphthenate is produced at higher temperatures. If allowed to cool, it solidifies. The point instrumentation was unable to detect these emulsion and naphthenate layers resulting in the instrumentation becoming fouled and ceasing to function. The separators were operated ‘blind’, using tri-cocks located on the side of the vessel, and as the instrumentation was installed in stilling wells inside the vessel, it was impossible to maintain them without shutting down and depressurising the vessels. This paper describes how nucleonic profiling instruments were retrofitted to the vessels and shows how their operation was able to identify the different layers within the separators. This enabled the time of oil production to be increased and allowed the pro-active use of effect chemicals such as emulsion breakers and defoamers to be applied before the plant became unstable.

Polymer-Flooding-Pilot Learning Curve: Five-Plus Years' Experience To Reduce Cost per Incremental Barrel of Oil

2014 ◽  
Vol 18 (01) ◽  
pp. 11-19 ◽  
Author(s):  
J.. Buciak ◽  
G.. Fondevila Sancet ◽  
L.. Del Pozo
Keyword(s):  
Learning Curve ◽  
Produced Water ◽  
Water Injection ◽  
Oil Production ◽  
Polymer Flooding ◽  
Oil Field ◽  
High Porosity ◽  
Polymer Injection ◽  
Injection Pump ◽  
Water Cut

Summary This paper deals with the learning curve of a five-plus-year polymer-flooding pilot conducted in a mature waterflood that includes, for example, several works related to injector and producer wells and reservoir management. The scope of this paper is to describe the learning curve during the last 5 years rather than the reservoir response of the polymer-flooding technique; focus is on the aspects related to reduce cost per incremental barrel of oil for a possible extension to other waterflooded areas of the field. Diadema oil field is in the San Jorge Gulf basin in the southern portion of Argentina. The field is operated by CAPSA, an Argentinean oil-producer company; it has 480 producer and 270 injector wells (interwell spacing is 250 m on average). The company has developed waterflooding over more than 18 years (today, this technique represents 82% of oil production in the field) and produces approximately 1600 m3/d of oil and 40 000 m3/d of gross production (96% water cut) with 38 400 m3/d of water injection. The reservoir that is polymer-flooded is characterized by high permeability (average of 500 md), high heterogeneity (10 to 5,000 md), high porosity (30%), very stratified sandstone layers (4 to 12 m of net thickness) with poor lateral continuity (fluvial origin), and 20 °API oil (100 cp at reservoir conditions). Diadema's polymer-flooding pilot started in October 2007 on five water injectors (it includes 13 injectors today) with an injected rate of 1000 m3/d (today, 2000 m3/d). Polymer solution is made with produced water (15,000 ppm brine) and 1,500 ppm of hydrolyzed polyacrylamide polymer reaching 15- to 20-cp fluid-injection viscosity. Oil-production rate from the original “central” producers (wells that are aided with 100% of polymer injection) has increased 100% at the same time as average reduction in water cut is approximately 15%. The main aspects presented in this work are depth profile modification with crosslinked gel injected along with polymer, use of “curlers” to regulate injection in multiple wells with one injection pump without shearing the polymer, and an improved technology on producer wells with progressing-cavity pumps to decrease shut-in time and number of pump failures. The plan for the future is to extend this project to other areas with the acquired knowledge and to improve different aspects, such as water quality and optimization of polymer plant operation. These improvements will allow the company to reduce operating costs per incremental barrel of oil.

Optimising Oil Field Net Present Value with Produced Water Salinities and Tracers

2021 ◽  
Author(s):  
Babalola Daramola
Keyword(s):  
Reservoir Simulation ◽  
Produced Water ◽  
Water Injection ◽  
Oil Production ◽  
Oil Field ◽  
Water Flooding ◽  
Water Salinity ◽  
History Match ◽  
Infill Drilling ◽  
Salinity Data

Abstract This paper presents case studies of how produced water salinity data was used to transform the performance of two oil producing fields in Nigeria. Produced water salinity data was used to improve Field B’s reservoir simulation history match, generate infill drilling targets, and reinstate Field C’s oil production. A reservoir simulation study was unable to history match the water cut in 3 production wells in Field B. Water salinity data enabled the asset team to estimate the arrival time of injected sea water at each production well in oil field B. This improved the reservoir simulation history match, increased model confidence, and validated the simulation model for the placement of infill drilling targets. The asset team also gained additional insight on the existing water flood performance, transformed the water flooding strategy, and added 9.6 MMSTB oil reserves. The asset team at Field C was unable to recover oil production from a well after it died suddenly. The team evaluated water salinity data, which suggested scale build up in the well, and completed a bottom-hole camera survey to prove the diagnosis. This justified a scale clean-out workover, and added 5000 barrels per day of oil production. A case study of how injection tracer data was used to characterise a water injection short circuit in Field D is also presented. Methods of using produced water salinity and injection tracer data to manage base production and add significant value to petroleum fields are presented. Produced water salinity and injection tracer data also simplify water injection connectivity evaluations, and can be used to justify test pipeline and test separator installation for data acquisition.

The Don Field, Blocks 211/13a, 211/14, 211/18a, 211/19a, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 257-263
Author(s):  
A. D. Milne ◽  
A. M. Brown
Keyword(s):  
North Sea ◽  
Middle Jurassic ◽  
Water Injection ◽  
Oil Production ◽  
Injection Well ◽  
Northern North Sea

abstractCumulative oil production to the end of 2000 from the Don Field was 15.4 MMBBLS, which with an estimated STOIIP of 152 MMBBLS represents a recovery to date of 10%. Don has been producing for over ten years. The field lics 15 km N of the Thistle Field, at the western edge of the Viking Graven in the northern North Sea. The structure of the field is complex, and it comprises several segments, the two larges of which have been developed, Don NE and Don SW. The reservoir sequence is Middle Jurassic Brent Formation. But more deeply buried and of a more distal facies than is typical for other fields in the province.The Don Field is a sub-sea development tied-back to the Thistle platform, and Britoil (BP) is the operator. The field has been developed with five producers, three in NE andtwo is SW, with a supporting water injection well in each part of the field. All wells have been drill deviated from a seabed manifold located over Don NE.

scholarly journals Oilfield Produced Water Management: Treatment, Reuse and Disposal

2012 ◽  
Vol 9 (1) ◽  
pp. 124-132 ◽  
Author(s):  
Baghdad Science Journal
Keyword(s):  
Oil And Gas ◽  
Produced Water ◽  
Water Injection ◽  
Oxygen Depletion ◽  
Low Levels ◽  
Produced Waters ◽  
Water Cut ◽  
Basic Features ◽  
Lead Nickel ◽  
Guide Lines

Produced water is accompanied with the production of oil and gas especially at the fields producing by water drive or water injection. The quantity of these waters is expected to be more complicated problem with an increasing in water cut which is expected to be 3-8 barrels water/produced barrel oil.Produced water may contain many constituents based on what is present in the subsurface at a particular location. Produced water contains dissolved solids and hydrocarbons (dissolved and suspended) and oxygen depletion. The most common dissolved solid is salt with concentrations range between a few parts per thousand to hundreds parts per thousand. In addition to salt, many produced waters also contain high levels of heavy metals like zinc, barium, chromium, lead, nickel, uranium, vanadium and low levels of naturally occurring radioactive materials (NORM).This study will highlight the main aspects of the different international experiences with the produced water treatment for subsequent reuse or disposal. These different treatment methods vary considerably in effectiveness, cost and their environmental impacts. Samples of produced water from Al-Mishrif formation in ten wells belongs to five fields southern Iraq were taken and analyzed chemically to define the basic features of these waters and to have guide lines for the best strategy that required handling the increased water cut in these fields.

A study on the quantities and potential use of produced water in southern Iraq

2014 ◽  
Vol 15 (2) ◽  
pp. 370-376 ◽  
Author(s):  
B. I. H. Waisi ◽  
U. F. A. Karim ◽  
D. C. M. Augustijn ◽  
M. H. O. Al-Furaiji ◽  
S. J. M. H. Hulscher
Keyword(s):  
Chemical Composition ◽  
Produced Water ◽  
Water Injection ◽  
Oil Production ◽  
Quality Standards ◽  
Peak Oil ◽  
Salt Tolerant ◽  
Water Shortages ◽  
Southern Iraq ◽  
Potential Use

This paper presents the results of an analysis of volumes and chemical composition of produced water (PW) accompanying oil production from five of the largest oilfields in the world situated in Basrah, Iraq. PW is potentially a valuable water resource particularly there where the ramp up of oil production puts further strains on water and the environment in an area already having severe water shortages. PW should therefore be seen as part of the country's strategic water reserves rather than as effluent. This study gives first estimates of anticipated PW volumes correlated to peak oil production and water consumption needs with time up to 2035. At least a fivefold increase of PW within the next two decades relative to the current 1 Mbbl/d can be anticipated. The estimated PW quantity before 2030 represents nearly a third of water injection or salt-tolerant plant irrigation needs. These quantities and the chemical composition of PW from these fields indicate that quality standards for these purposes can be technically attained and sustained for use in Basrah.

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