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Treatment evaluation leads to problem identification and to continuously improved treatments. The prime source of information on which to build an evaluation are the acid treatment report and the pressure and rate data during injection and falloff. Proper execution, quality control, and record keeping are prerequisites to the task of accurate evaluation. Evaluation of unsatisfactory treatments is essential to recommending changes in chemicals and/or treating techniques and procedures that will provide the best treatment for acidizing wells in the future. The most important measure of the treatment is the productivity of the well after treatment.
In formations with over 1% carbonate, an HCl or acetic acid preflush dissolves the carbonate to prevent waste of HF acid and formation of the insoluble precipitate calcium fluoride. Calcium and sodium chloride workover brine also must be flushed away from the wellbore with HCl acid or ammonium chloride brine. Preflushes also displace and isolate incompatible formation fluids (either brine or crude oil). Higher concentrations of ammonium chloride ( 3%) are recommended where swellable smectite and mixed layer clays are present. For successful HF acidizing, more than 120 gal/ft of HF/HCl acid is usually required.
You've decided that your well is a good candidate for acidizing, assessed the formation, designed the treatment, prepared the well and equipment, so now you're ready to conduct the treatment. This page describes both the process and things you should be doing during and immediately after the treatment. The main acid job should be circulated in place with HCl acid placed across the formation before the packer is set or before the bypass valve is closed. All perforations should be covered by acid before injection starts. Injection should start at a predetermined injection rate and the pressure observed to determine the condition of the wellbore.
The success of an acidizing operation can be compromised if the wellbore, tanks, or other equipment contain solids or other contaminants that could flow into the well or formation. Proper preparation is a key factor in a successful acid treatment. Treating fluids must leave surface tanks, travel through surface pipe and well tubing, enter a wellbore, and pass through the perforations into the formation so that the solvent can react with the damaging solids. Each of these components through which the fluid travels must be properly cleaned before pumping acid into the formation. Surface tanks must be cleaned before being filled with acid.
An acid additive is any material blended with acid to modify its behavior. Because acid is so naturally corrosive, the development of an additive to reduce acid attack on steel pipe was the first requirement for successful acidizing. Development of a suitable corrosion inhibitor started the acidizing service industry in 1932. Comprehensive testing and application of corrosion inhibitors is still necessary in successful acidizing. Many acid additives are available, but those that are usually necessary are corrosion inhibitors, surfactants, and iron control agents.
Since the most common use of matrix acidizing is the removal of formation damage, it is important to understand the nature of the damage that exists so that an appropriate treatment can be designed. Well testing and well test analysis generate a skin factor and well completion efficiency. This is insufficient alone for formation damage diagnosis. Well performance analysis has provided a beneficial tool to identify the location and thickness of damage at flow points in the near wellbore area. Models of flow into perforations and gravel-packed tunnels provide a way to relate the location and severity of damage to the completion procedure that preceded it.
The paper describes a novel methodology to construct distributed formation damage across openhole wells in carbonate reservoirs and to evaluate the effects of damage on zonal productivity. This methodology improves the prediction of well productivity by identifying the contribution of various types of damage to zonal productivity. This is critical for efficient decision making concerning well-completion and field-development options, particularly at the early stages of greenfield development. Numerous papers have investigated near-wellbore damage caused by drilling and acid, but the majority of these studies assume a homogeneous anisotropic reservoir and a perfectly horizontal well with constant diameter. In practice, these assumptions are unrealistic, especially when dealing with multi layered carbonate reservoirs.
Bakar, Hasmizah (PETRONAS Carigali Sdn Bhd) | Faris W Hassan, W M (PETRONAS Carigali Sdn Bhd) | Kumar, Suman (PETRONAS Carigali Sdn Bhd) | Faliq Jamal, Ajmal (PETRONAS Carigali Sdn Bhd) | Magna Bela, Sunanda (PETRONAS Carigali Sdn Bhd) | Fiqri Hairi, Helmi (PETRONAS Carigali Sdn Bhd) | Latif, Nurlizawati (PETRONAS Carigali Sdn Bhd) | Hashim, Saharul (Halliburton) | Tham, Dennis (Halliburton) | Shahabuddin, Syukri (Halliburton)
Abstract A 7-in. single-trip multizone (STMZ) gravel pack system was installed successfully in two wells in the T field, Sarawak offshore. This paper highlights the system performance and knowledge obtained during this first-time installation performed in Malaysia. The most common sand control techniques established in the H, I, and J sands of this mature field include stacked gravel pack, 9 5/8-in. single-trip multizone gravel pack, and openhole standalone sand screen (OHSAS) systems. Internal gravel pack completions have provided proven, robust sand control for the sand-prone reservoirs in the T field and can save four to five days of rig time depending on the well configuration, compared with the standard stacked gravel pack completion, which was initially planned during the field development plan (FDP) stage. This paper presents the extensive technical works performed post-FDP approval to ensure the change from the 7-in. stacked gravel pack to the 7-in. single-trip multizone gravel pack completion was executed safely and efficiently and most importantly able to maximize the recoverable reserves from the multiple unconsolidated reservoirs. The technical challenges, such as unexpected drilling of additional zones, limited annulus clearance between the 7-in. liner and gravel pack tool string to reverse out proppant efficiently, intersands spacing, and gross sand interval constraints within certain tolerance because of bottomhole assembly (BHA) limitations, are also discussed. The 7-in. single-trip multizone gravel pack installation helped reduce rig time and provided a cost savings of nearly USD 1.1 million. Subsequently, the two oil-producing (OP) wells (two OP wells and four OP strings) are producing sand-free at higher than expected reserve and flow rates.
The requirement for appropriate placement in matrix acidizing to achieve efficient, effective stimulation or removal of formation damage has long been recognized. Despite this, assessing the effectiveness of an acid treatment in terms of placement and treatment efficiency prior to field deployment remains a challenge.
This paper presents a scenario where carefully designed core flood tests have been deployed alongside the use of a near-wellbore simulator to model and predict acid stimulation using viscosified fluids for treatments in a range of scenarios. Dual linear core flood tests were conducted to assess placement and clean-up efficacy of a viscosified acid treatment.
The efficiency of the treatment was then modelled using a state-of-the-art computer simulator. The computer simulator used is one which has been used extensively to model and optimize scale-inhibitor squeeze treatments in long-reach/complex wells. Its capability was extended to evaluate effects of fluid viscosification (staged or otherwise) on stimulation treatments.
Cases where partial/localised clean-up of a damaged zone was achieved, resulting in uneven stimulation were also examined. Results obtained from the model were validated with dual-linear core flood tests using simulated damaged and non-damaged zones. Resulting laboratory injection/diversion was compared to model predictions.
Core flood tests highlighted the importance of laboratory simulation of viscosified treatments. These tests showed how improved placement can be achieved by careful fluid design using viscosity alterations. The model was used to demonstrate the benefit (or otherwise) of different degrees of viscosification on evenness of treatment placement for systems with permeability contrasts, pressure differentials, presence of a water-producing zone, and various degrees and depths of skin per zone (including consideration of the effects on placement of acid reactivity on this damage).
Results showed that often even modest viscosification of the treatment fluid (~20 cP) improved placement. The greater the fraction that was viscosified (for staged treatments), the more even the placement. Viscosification invariably improved placement where a difference in native permeability existed (as opposed to a difference due to damage) and in most cases reduced the fraction of treatment fluid entering a water-producing zone.
Oil and gas companies operating carbonate oil and gas condensate fields in Kazakhstan have been carrying out acid stimulation activities leading to a substantial increase in hydrocarbon production. Nearly all treatments were considered a success. Nevertheless, a certain level of optimization in the production enhancement methods that could, potentially, have brought additional technical and financial benefits, were overlooked due to various reasons.
A comprehensive review of historical treatments on several fields located in West-Kazakhstan region was performed to identify areas to improve post-stimulation well performance. This review identified improvements including "cleaner" fluid selection, optimised design and treatment schedules. Historical treatments in the oil field typically used straight hydrochloric acid as the main acid, polymer-gelled (self-diverting) acid as the chemical diverter, and linear guar gel for displacement, and diagnostic tests. The application of a modern single-phase retarded acid to replace the straight hydrochloric acid was identified as a key improvement that would yield more efficient wormhole generation and an improved stimulation ratio. Another opportunity for improvement was to upgrade the chemical diversion system from polymer-based self-diverting acid to a viscoelastic surfactant-based (polymer-free) diverting acid system. The use of an oil-based displacement fluid with high retained permeability instead of linear gel and to reduce the hydrostatic pressure post-acidizing, thereby improving flowback, was also employed.
Extended core flow testing for regained permeability and solubility were carried out with several acid systems to compare their capabilities and efficiency to create conductive wormholes, and their dissolution capacities. Additionally, emulsion, and sludging tendency upon contact with wellbore tubulars and formation crude was checked to verify the acids’ compatibility with hydrocarbons produced from the target reservoir. After the prerequisite laboratory testing, field trials commenced applying various combinations of fluid technologies in high-rate matrix stimulation treatments. The optimizations resulted in higher (normalized) post-stimulation productivity index (PI), facilitated formation cleanup, and enabled more efficient operations. A similar approach is, currently, being implemented in other stimulation projects in the region, and the results are being replicated.
As has been mentioned above, one of the main enhancements implemented as part of this work is the employment of the single-phase retarded acid. Most of the published literature discussing application of the acid covers the cases of stimulation of relatively hot reservoirs (BHST>100°C) as acidizing of high-temperature carbonate rock using traditional hydrochloric acid is a great challenge. The current paper provides details of the case studies, where the acid system was successfully implemented in combination with several other stimulation technologies for mid-temperature ranges. One of the objectives was also to assess whether application of reduced volumes of the retarded and diverting acids would still lead to improved wells’ productivity. Positive results of the laboratory studies, treatment modeling, and field trials were validated by the increasing normalized post-stimulation PI with each optimization step.