Optimising the Placement of Acid Treatments for Damage Removal and Well Stimulation
Abstract: 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 usi… Show more
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Cited by 3 publications
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The role of the subsurface team is to reduce technical risk and uncertainty associated with profile delivery, for both hydrocarbon production and the injection of water or gases, enabling confident reservoir management and investment decisions. Core is a key resource for delivering this objective, providing the only opportunity to directly observe and measure the reservoir rock. However, it is expensive to acquire and the decision to take new core should be clearly linked to a business objective. A combination of depositional and diagenetic factors can result in carbonate reservoirs being highly heterogeneous, making them a challenge to find and develop. Core studies can significantly improve understanding of the controls on heterogeneity and its distribution within the subsurface, but to maximize value, they should be fully integrated with wireline logs, seismic and production or test data to predict likely reservoir behaviour. For example, thin (<1 m) high or low permeability zones can dominate production yet remain very subtle or undetectable in wireline log or seismic data alone. During exploration and appraisal, sufficient data and knowledge are required to enable appraise/develop or walk-away decisions. Appropriate geological description of core material helps to establish original volumes in place, net-to-gross, depositional setting, age, reservoir architecture and large-scale flow zones. Core material can also help establish other key reservoir parameters such as saturation, reservoir fluids, seismic rock properties and geomechanical properties as well as influencing decisions such as well design, development strategy and facility requirements. As a field is developed and production matures, reservoir behaviour may change and detail of the sedimentology, structure, diagenesis, baffles and thin heterolithic permeability zones may become more important. In carbonate reservoirs this often requires the integration of existing legacy core or new core material and targeted surveillance data e.g. injection and production logging tool (ILT/PLT) or saturation logs, to understand the stratigraphic, depositional and diagenetic controls on flow units and improve predictive capability. Moving a reservoir from natural depletion onto waterflood or enhanced oil recovery (EOR) may need more advanced core-based data from core flood experiments, to deliver maximum value from the reservoir. New core material, or detailed review and new sampling of existing or analogue legacy core, may be required to understand complex rock-fluid interactions and the value that waterflood or EOR could bring to a development. To maximize the value and insights gained from core it is essential to use it throughout a field's life. High quality description and a well-considered sampling regime should be carried out at the earliest opportunity to provide baseline data. However, periodically revisiting the core enables the entire subsurface team to keep testing hypotheses and refreshing models. Where there is no core material available in the field, analogue field core can be especially useful both to narrow uncertainty and explore possible alternative models. A multi-disciplinary approach, integrating new data with core observations helps refine and improve predictions, and can lead to the identification of significant additional opportunities as reservoir behaviour matures and field development progresses.
The role of the subsurface team is to reduce technical risk and uncertainty associated with profile delivery, for both hydrocarbon production and the injection of water or gases, enabling confident reservoir management and investment decisions. Core is a key resource for delivering this objective, providing the only opportunity to directly observe and measure the reservoir rock. However, it is expensive to acquire and the decision to take new core should be clearly linked to a business objective. A combination of depositional and diagenetic factors can result in carbonate reservoirs being highly heterogeneous, making them a challenge to find and develop. Core studies can significantly improve understanding of the controls on heterogeneity and its distribution within the subsurface, but to maximize value, they should be fully integrated with wireline logs, seismic and production or test data to predict likely reservoir behaviour. For example, thin (<1 m) high or low permeability zones can dominate production yet remain very subtle or undetectable in wireline log or seismic data alone. During exploration and appraisal, sufficient data and knowledge are required to enable appraise/develop or walk-away decisions. Appropriate geological description of core material helps to establish original volumes in place, net-to-gross, depositional setting, age, reservoir architecture and large-scale flow zones. Core material can also help establish other key reservoir parameters such as saturation, reservoir fluids, seismic rock properties and geomechanical properties as well as influencing decisions such as well design, development strategy and facility requirements. As a field is developed and production matures, reservoir behaviour may change and detail of the sedimentology, structure, diagenesis, baffles and thin heterolithic permeability zones may become more important. In carbonate reservoirs this often requires the integration of existing legacy core or new core material and targeted surveillance data e.g. injection and production logging tool (ILT/PLT) or saturation logs, to understand the stratigraphic, depositional and diagenetic controls on flow units and improve predictive capability. Moving a reservoir from natural depletion onto waterflood or enhanced oil recovery (EOR) may need more advanced core-based data from core flood experiments, to deliver maximum value from the reservoir. New core material, or detailed review and new sampling of existing or analogue legacy core, may be required to understand complex rock-fluid interactions and the value that waterflood or EOR could bring to a development. To maximize the value and insights gained from core it is essential to use it throughout a field's life. High quality description and a well-considered sampling regime should be carried out at the earliest opportunity to provide baseline data. However, periodically revisiting the core enables the entire subsurface team to keep testing hypotheses and refreshing models. Where there is no core material available in the field, analogue field core can be especially useful both to narrow uncertainty and explore possible alternative models. A multi-disciplinary approach, integrating new data with core observations helps refine and improve predictions, and can lead to the identification of significant additional opportunities as reservoir behaviour matures and field development progresses.
A Wholistic Approach for Successful Chemical Sand Consolidation Treatments in High Sand Producing Wells
Sand production in oil and gas wells is a challenge which results in operational issues and can ultimately lead to significant losses. Chemical sand consolidation treatments can be a viable alternative to mechanical solutions in certain scenarios and can provide additional recovery benefits over operational sand control methods. This paper examines a chemical sand consolidation option for successful sand control treatments using a North Sea scenario. While the chemistry presented herein has been used in previous scenarios, this paper aims to bridge the gap in treatment success by utilising a wholistic approach from product selection, laboratory qualification, candidate well selection, to field deployment and therefore provide a template for successful chemical sand control deployments. The selected chemistry, which is an oil based organo-silane chemistry aims to increase the maximum sand free production rate with minimal formation damage. Laboratory qualification for the specific field application was conducted using core flood testing on field core. Coreflood tests examined a blank (for baseline damage and sand loss) and a 6% (in diesel) product application to assess formation damage and consolidation. Several diagnostic analyses methods were employed to track product deposition in the core and assess its overall effectiveness in sand reduction. Advanced sand loss tests using reservoir rock was used to quantify consolidation as a percentage of sand loss. Product compatibility with field oil was also assessed. A candidate well was considered and selected based on field experience and success criteria for the chemical. This well is presently shut-in due to excessive sand production and resumption of production is unlikely without some form of intervention. The selected chemistry showed no incompatibility with field condensate and the proposed carrier oil. The baseline Coreflood test showed no evidence of formation damage. When 6% of the product was applied, an acceptable level of permeability loss was recorded. Diagnostic scanning electron microscopy (SEM) images of the core showed a network of the organo-silane product between the sand grains which is responsible for tightly binding the grains together. Baseline sand loss test on crushed reservoir sand showed 86% sand loss and this was reduced to 16% when the sand was treated with 4% of the organo-silane chemistry. Core flood test data combined with diagnostic SEM and sand loss analysis show a potentially effective treatment, with a combination of permeability recovery and the deposition of a sand consolidating coating on the pores that remained in place after multiple pore volumes of brine and oil backflush. These advanced qualification steps paved the way for field treatment design, and for deployment of this product in the selected well. This paper highlights a chemical sand consolidation product which has the potential to improve consolidation and increase the maximum sand free rate for enhanced production. This technology offers the potential to deploy a cost-effective chemical solution to excessive sand production without the requirement for mechanical intervention or well re-completion. Importantly, this paper bridges the critical knowledge gap in product selection and laboratory qualification while highlighting appropriate well candidacy and deployment as critical factors for successful field treatments.
Executive Summary The objective of this study is to compare the performances of Underbalanced Coiled Tubing Drilling (UBCTD) versus conventional drilling with stimulation in a Permian carbonate target within a field in Saudi Arabia. The focus of this study is to ultimately investigate the effectiveness of biosteering in UBCTD compared to geosteering and subsequent stimulation in conventional drilling of vertical and horizontal wells within the same target. Biosteering is an application of biostratigraphy used to navigate and maintain well paths within the desired zone. This technique has been employed successfully in UBCTD wells in the Middle East. Biosteerers utilize the characteristic distribution of microfossil assemblages obtained from cuttings samples with the identification of biozones based on existing schemes. The most effective way to geosteer these well is to use this technique in conjunction with lithology descriptions, GR log trends, visible porosity and drilling parameters. UBCTD wells are not stimulated as there is minimal induced formation damage during drilling operations. Geosteering utilizes logging while drilling (LWD) in horizontal wells for lateral placement and to determine perforation intervals. Conventional wells in this study are all stimulated, employing multistage acid fracturing techniques. The dataset in this study comprises 50 wells, all of which are compared by normalized post-completion performance. Post-completion performance from the 50 well dataset was normalized to achieve a representative comparison. UBCTD biosteered wells show indicative superiority when compared to horizontal and vertical conventionally drilled and stimulated wells. In addition to the minimal formation damage in underbalanced wells, footage in the target is higher in biosteered UBCTD wells compared to geosteering. This is due to several reason with the main reason being is the ability of UBCTD to drill multiple laterals in each well, thus maximizing target contact. A detailed look into two wells targeting the same formation and field proved effective UBCTD utilization, yielding a production increase of several orders of magnitude. Despite these results, the normalized production performance may not account for significant LWD merits. In terms of steering, UBCTD slim-hole nature limits applications of available LWD technologies that provide essential information for reservoir characterization and development plans.
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