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Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability. When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.
This page discusses the primary manner in which the immiscible gas/oil displacement process has been used in qualitative terms. This is the use of gas injection high on structure to displace oil downdip toward the production wells that are completed low in the oil column. In many cases, an original gas cap was present, so the gas was injected into that gas cap interval (see Figure 1 for cross-sectional view of anticlinal reservoir with gas cap over oil column with dip angle α and thickness h). In this situation, the force of gravity is at work, trying to stabilize the downward gas/oil displacement process by keeping the gas on top of the oil and counteracting the unstable gas/oil viscous displacement process. If the oil production rate is kept below the critical rate, then the gas/oil contact (GOC) will move downward at a uniform rate.
Traditional well plugging and abandonment (P&A) methods are not efficient. For example, section milling is time-consuming and expensive because of the number of rig days required. The milling produces cuttings, which have to be handled. Contamination of the milling fluid with oil-based mud (OBM) requires separation before disposal. Cutting casing requires pulling it from the hole.
This work describes the positive results experienced when a self-diverting acid system based on a viscoelastic-surfactant (VES) technology was introduced for carbonate-reservoir stimulation offshore Brazil. The self-diverting (SD) VES (SD-VES) promotes viscosity development when the acid comes in contact with the carbonate formation. Since the SD-VES was introduced in this environment in 2009, more than 40 wells have been treated with the system. Matrix acidizing is frequently used to stimulate carbonate reservoirs offshore Brazil. In these treatments, a proper diversion technique is required to direct the treatment fluid to lower-permeability or more-damaged zones and ensure the treatment of the entire production interval.
The post-acid-fractured well productivity index (PI) showed the high quality of the stimulation performed in a challenging environment, demonstrating the effectiveness of the new diversion system for creating selective fractures in a horizontal wellbore with multiple perforation clusters. Completion of deep HP/HT carbonate formations in northern Kuwait in overpressured environments comprising interbedded carbonate bodies, complex tectonics, and stress variations resulting in strike/slip or reserve fault regimes is challenging for operator and service companies. Because of the low-permeability conditions, it is necessary to generate long and conductive fractures to produce the reservoir effectively. Additionally, this aggressive fracture-stimulation requirement needs to overcome the high-working-pressure limitations of the completion, in addition to the nature and corrosiveness of the produced hydrocarbon, which makes selection of the proper stimulation reactive-fluid system important. These challenges are even more crucial in cases having drilling and completions issues.
The authors examine methods of adopting an aggressive approach to optimizing stimulation design to lower the break-even level of operations and evaluate the results. Operators achieved significant improvements in production by changing parameters in the fracturing and completion design strategy, including, but not limited to, the amount of water used, the amount of sand pumped, stage spacing, maximum sand concentration, and fracturing-fluid selection. The complete paper addresses the importance of aggressive design, its evolution, and its enabling technologies. Although completion practices and production numbers vary from basin to basin and from play to play, certain high-level trends remain in the development of unconventional reservoirs over the past few years. In most places, operators have been drilling increasingly longer laterals.
Teo, Choon Hoong (Sarawak Shell Berhad) | Bakri, Faiz (Sarawak Shell Berhad) | Koh, Qianhui (Sarawak Shell Berhad) | Mat Jusoh, Muhammad Faizol (Sarawak Shell Berhad) | Bin Alias, Saiful Hisham (Archer Well Company) | Othman, Azmi (Archer Well Company) | Idris, Syahiran (Halliburton Energy Services) | Thien, Ronny (Halliburton Energy Services)
Abstract Following the successful proof of concept of the closed system dual casing perforate, wash and cement for environmental plug application in 2018 (SPE-193989-MS), the same system was optimized for 2 subsea wells to isolate a gas sand behind 2 casings (9-5/8" × 13-3/8" × 16" open hole). Learning from recent operations, it was discovered that there is significant improvement achievable with specialized gun system, and refined washing and cementing parameters. Such improvement was critical to the success of the annular remediation and thus, the long-term isolation of the gas sand. The first successful closed system dual casing perforate, wash and cement for annular isolation is discussed and evaluated in this paper.
The main goal of matrix acidizing in carbonate reservoirs is to create wormhole and to remove the damage caused by drilling on the wellbore wall. The critical step in acidizing design is to optimize the design parameters for uniformly distributing the stimulation fluid. Non-engineered designed acidizing jobs will lead to softening the near wellbore rock and with time it will have a negative effect on the production. In this work, we present design and modelling of particulate diversion process using an integrated Geomechanical workflow for case histories from South America.
The model utilized petrophysical data of the formation, stresses near wellbore, wellbore flow, rock dissolution and physical model. The case history of 2 deviated wells from North and South America respectively were simulated with the stimulation fluid movement within wellbore and then it was coupled with transient flow. The primary analysis determines the distribution of reactive fluid along the well and predicted skin and wormhole evolution across the wellbore upon stimulation.
This work introduced an integrated engineering workflow to optimize and simulate carbonate matrix acidizing design using bio-degradable particulate diverters and demonstrate uniform stimulation with reduction in skin. In the presented case study, 2 jobs from North and South America were analyzed. The results demonstrate effectiveness of particulate diverters in reducing the wellbore damage, uniformly distributing the treatment fluid, increasing effectiveness of stimulation fluid, retarding the softening of rock and hence enhancing the production across the target zone.
This Geomechanics model for particle diversion permits a dependable prediction of stimulation fluid distribution across the reservoir section and identifies controlling parameters to maximize conductive reservoir volume (CRV), avoids premature collapse of wormhole, uniform distribution of the stimulation slurry and hence enhances production. The presented case study can assist in building a customized diversion strategy for Middle East carbonate formations.
Skutin, Vasilii (TGT Diagnostics) | Abasher, Doha (TGT Diagnostics) | Izawa, Toshihide (ADOC) | Watanabe, Kimihiko (ADOC) | Nihei, Shotaro (ADOC) | Kuramata, Hideaki (ADOC) | Iwasaki, Satoshi (ADOC) | Matsuda, Hiroki (ADOC) | Nakata, Nakata (ADOC) | Alobeidli, Abdulla (ADNOC)
This paper will describe pre and post workover well diagnostic and the successful water shut-off that has resulted. It also talks about the post workover survey. The well was recently completed to a new targeted reservoir and suffered from high water cut (80%) at the start of production. Proper diagnostics identified the source of water and helped in planning a successful remedial job. After water shut off the water cut dropped to zero. Post workover evaluation confirmed production from the targeted interval.
Comprehensive diagnostics are crucial to designing a proper remedial job. A conventional PLT survey will describe the flow characteristics and parameters inside the wellbore only. During the job under consideration, two additional services were deployed; the Spectral Noise Logging and the High Precision Temperature sensing. Their combination with the PLT allows for the assessment of behind casing flow and the identification of active streaks of the formation. The quantification of flow rate behind casing is also achieved by modelling the temperature response from the high precision sensor.
The first survey was conducted with the conventional PLT to identify the source of water. Subsequently, a high precision temperature and spectral noise log were recorded under flowing, transient, and shut-in conditions. A crossflow behind casing from the upper unperforated intervals was identified. The main liquid production is coming from the water-bearing formation that is located 15 ft above the targeted reservoir. The cement evaluation surveys that were run previously confirmed the presence of a cement channel above of the perforated interval. Based on these conclusions a remedial job was designed and conducted successfully. Another HPT/SNL survey was conducted post workover. It confirmed the absence of any further flow behind casing and that all liquid production is happening from the targeted reservoir. Surface test data showed a rapid decrease in water production to 1% post workover.
This paper highlights the importance of complementing the current practice of running conventional PL surveys with two additional services: the Spectral Noise Logging and Temperature simulation/modelling using a High Precision Temperature measurement.
Holmes, Michael (Digital Formation, Inc.) | Holmes, Antony (Digital Formation, Inc.) | Holmes, Dominic (Digital Formation, Inc.) | Swartz, Kent (Valkyrie Operating) | Jones, Brian (Valkyrie Operating) | Aye, Naing (Valkyrie Operating) | Zimbrick, Grant (Dolan Integration Group)
The main objective is to build on prior publications of decline curve analysis, based on theoretical producing and fluid flow characteristics (Matthews and Lefkowits 1956, Fetkovitch 1975,
In this paper, we relate petrophysical predictions of ultimate oil recovery to actual rate-time well performance by adjusting recovery efficiencies and well-bore drainage areas.
From an analysis of a number of producing wells in the Permian Basin a model (Zimbrick) has been derived for average decline curve performance. This model has been found to work in other basins; however, basin specific models are likely to be required in some situations.
This model is then combined with petrophysical estimates of recovery efficiencies to generate rate vs. time decline curves. This is then compared with actual production to determine drainage area. Three basic questions are then addressed:
Is the drainage area reasonableš
Is the recovery assumption reasonableš
Does the petrophysical analysis need adjustmentš
Additional adjustments might then be necessary. Results can be interpreted as follows:
If the petrophysical analysis suggests the well is under-performing, reservoir quality has degraded within the drainage area.
If the petrophysical analysis suggests the well is over-performing, reservoir quality is better than predicted. This could be a consequence of contribution from a fracture system and/or from adjacent reservoirs close to the perforated interval.
Results from the analyses of four oil wells in the Big Horn Basin of Wyoming are presented. All four wells have excellent log suites allowing for reliable petrophysical analysis, are now depleted, and have rate-time data available.
The nominal well spacing is for 15-acre drainage. Petrophysical predictions for rate-time performance were run for two basic cases:
For only the perforated intervals - often four of five within the gross perforated interval.
For the gross perforated interval - petrophysical analyses indicated additional pay that was not perforated.
Using a constant recovery efficiency of 20% the drainage areas were adjusted to get an exact match with actual performance.
For three of the four wells, adjusted drainage areas are significantly greater than 15 acres.
Factors influencing the calculated drainage areas are:
There is no well interference and drainage is occurring from adjacent undrilled acreage.
Recovery efficiencies are higher than 20%
Oil is coming from zones additional to the gross perforated interval, or from a fracture system.
The method compares petrophysical estimates of recoverable hydrocarbons with actual rate-time performance, allowing for considerations of drainage areas and recovery efficiencies and the possibility of production coming from a fracture system and/or adjacent unperforated intervals.
Estimates can be made from the petrophysical analysis of adjacent undrilled locations of rate-time performance before the well is completed.