An Active Method for Characterization of Flow Units Between Injection/Production Wells by Injection-Rate Design

2011 ◽  
Vol 14 (04) ◽  
pp. 433-445 ◽  
Author(s):  
Kun-Han Lee ◽  
Antonio Ortega ◽  
Amir Mohammad Nejad ◽  
Iraj Ershaghi
Keyword(s):  
Reservoir Characterization ◽  
Injection Rate ◽  
High Permeability ◽  
Injection Wells ◽  
Flow Units ◽  
Weight Factors ◽  
Production Wells ◽  
Preferential Flows ◽  
Injection Rates

Summary This paper presents a novel data-mining method to characterize the flow units between injection and production wells in a waterflood, using carefully implemented variations in injection rates. The method allows the computation of weight factors representing the influence of any of the injectors surrounding a given producer. The weight factors are used to characterize the effective contribution of injection wells to the total gross production in surrounding production wells. A wavelet approach is used to design the perturbation in the injection rates and to analyze the observed variations in the gross production rates. Tracking the contribution of injectors to various producers can help in balancing voidage replacement in waterflood optimization. A second application is reservoir characterization, in which information provided by the proposed procedure can help in mapping high-permeability flow units such as channels and fractures as well as flow barriers between wells. The method was calibrated and tested successfully for simulated line-drive and five-spot patterns with various assumed flow units and flow-heterogeneity conditions. The paper also includes a case study for a tight-formation waterflood in which the weight factors are intended to delineate the pattern of natural high-permeability channels causing preferential flows.

scholarly journals Capillary processes increase salt precipitation during CO2 injection in saline formations

2018 ◽  
Vol 852 ◽  
pp. 398-421
Author(s):  
Helena L. Kelly ◽  
Simon A. Mathias
Keyword(s):  
High Salinity ◽  
Volume Fraction ◽  
Injection Rate ◽  
Injection Well ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Injection Wells ◽  
Tenfold Increase ◽  
Entry Pressure ◽  
Injection Rates

An important attraction of saline formations for CO2 storage is that their high salinity renders their associated brine unlikely to be identified as a potential water resource in the future. However, high salinity can lead to dissolved salt precipitating around injection wells, resulting in loss of injectivity and well deterioration. Earlier numerical simulations have revealed that salt precipitation becomes more problematic at lower injection rates. This article presents a new similarity solution, which is used to study the relationship between capillary pressure and salt precipitation around CO2 injection wells in saline formations. Mathematical analysis reveals that the process is strongly controlled by a dimensionless capillary number, which represents the ratio of the CO2 injection rate to the product of the CO2 mobility and air-entry pressure of the porous medium. Low injection rates lead to low capillary numbers, which in turn are found to lead to large volume fractions of precipitated salt around the injection well. For one example studied, reducing the CO2 injection rate by 94 % led to a tenfold increase in the volume fraction of precipitated salt around the injection well.

A Model for Water Injection Into Frac-Packed Wells

2010 ◽  
Vol 13 (03) ◽  
pp. 449-464 ◽  
Author(s):  
Ajay Suri ◽  
Mukul M. Sharma
Keyword(s):  
Water Injection ◽  
Horizontal Stress ◽  
Injection Rate ◽  
Injection Wells ◽  
Solids Concentration ◽  
Sand Control ◽  
Injection Water ◽  
Large Injection ◽  
Minimum Horizontal Stress ◽  
Injection Rates

Summary Frac packs are increasingly being used for sand control in injection wells in poorly consolidated reservoirs. This completion allows for large injection rates and longer injector life. Many of the large offshore developments in the Gulf of Mexico and around the world rely on these completions for waterflooding and pressure maintenance. The performance of these injectors is crucial to the economics of the project because well intervention later in the life of the field is expensive and undesirable. For the first time, we present a model for water injection in frac-packed wells. The frac pack and the formation are plugged because of the deposition of particles from the injected water, and their effective permeability to water is continuously reduced. However, as the bottomhole pressure (BHP) reaches the frac-pack widening pressure, the frac-pack width increases and a channel that accommodates additional injected particles is created. Injectivity depends on the interstitial velocity of the injected water in the frac pack, volume concentration of the solids in the injected water, injection rate, injection-water temperature, size of proppants in the frac pack, width and length of the frac pack, and the initial minimum horizontal stress. In case of frac packs with large proppant size and high injection rates, the plugging of the frac pack is found to be negligible except in the building of a filter cake at the frac-pack walls. In the case of narrow frac packs with small proppant, significant plugging is expected, which leads to sharp permeability decline of the frac pack and a rapid rise in the BHP. The long-term injectivity of a frac-packed injector depends primarily on the filtration coefficient value of the frac pack, solids concentration in the injected water, and the injection rate. Frac packs are expected to maintain higher injectivities compared to any other completions such as openhole, cased-hole, perforated, or gravel packs.

The Influence of Geology Factor on Alkaline Surfactant Polymer Flood Effect and the Corresponding Strategy

2016 ◽  
Vol 703 ◽  
pp. 251-255
Author(s):  
Peng Ye ◽  
Dong Zhang ◽  
Lian Bin Zhong ◽  
Guang Wang ◽  
Bin Fu ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Injection Rate ◽  
High Concentration ◽  
Injection Wells ◽  
Adjustment Strategy ◽  
Profile Control ◽  
Production Wells ◽  
Success Experience ◽  
Abandoned Channels ◽  
Alkaline Surfactant Polymer

This study gives the influence laws of abandoned channel, in-layer interlayer, sand body contact relationship on the development effect of the Alkaline Surfactant Polymer (ASP) flooding based on the data of the industry promotion block ( Pu I32、Pu I33 sedimentation), and give out corresponding adjustment strategy at the same time. The result shows that: The ‘abruptly abandoned’ channels have a bad connection with the main channel and possesses a far lower reservoir producing degree (16.1%) than the ‘gradually-abandoned’ channels (79.9%). The injection wells located upon the channel sand need high concentration inject fluid with lower injection rate to handle the polymer breakthrough; The injection wells located between the channels need lower concentration injection; The injection wells located upon the abandoned channels firstly need high concentration injection to achieve the profile control and then inject low concentration fluid to adjust low permeable sublayer; The production wells located upon abandoned channels need timely fracturing measures. By July 2014, water content of this area is 90.7%, oil recovery improved 18.08% and is expected to reach 22.0%. Similar the success experience we get from this area can guide the study of block geologic factors that affect development result and has important guiding significance to the implementation of pointed development adjustment.

scholarly journals Stratigraphic and Petrophysical Characteristics of Cored Arab-D Super-k Intervals, Hawiyah Area, Ghawar Field, Saudi Arabia

GeoArabia ◽  
2000 ◽  
Vol 5 (3) ◽  
pp. 355-384 ◽  
Author(s):  
Franz O. Meyer ◽  
Rex C. Price ◽  
Saleh M. Al-Raimi
Keyword(s):  
Saudi Arabia ◽  
Low Permeability ◽  
Unexpected Result ◽  
High Permeability ◽  
Flow Units ◽  
Ghawar Field ◽  
Injection Rates

ABSTRACT Super-permeability or super-k (as defined here), refers to confined intervals that have production or injection rates of at least 500 barrels of fluid/day/foot. Eight cored wells—four producers and four injectors—show super-k performance within the northern Hawiyah study area. One injector well had multiple super-k flow intervals. Super-k flow correlates with specific limestone, dolomite, or fractured intervals based on an analysis of core and flowmeter data. A thin, high-permeability unit sandwiched between low-permeability strata characterizes the sequential stratification of stratiform super-k flow units. Oolitic, mixed skeletal pelletoidal, foraminiferal, fragmented Cladocoropsis or Cladocoropsis lithofacies may make up the high-permeability conduits in limestones, and various mud-dominated facies form the tight enclosing layers. Sucrosic or vuggy fabrics characterize the highly permeable layers in dolomite-controlled intervals, and mosaic textures form the tight envelope. Production from stratiform dolomite is typically from one or more thin (generally less than six-inch thick) stringers some of which represent tempestite deposits. Super-k flow from fracture-controlled intervals has no correlation with either facies or dolomite textural boundaries. An unexpected result of this study was the discovery that not all super-k flow comes from high-permeability features such as fractures or zones of dolomitized leached Cladocoropsis. Instead, ordinary rock fabrics with normal permeability ranges (0.1 to 1 darcy) characterize most of the super-k intervals in six of the eight wells examined.

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