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Results
A Successful Acid Fracturing Treatment in Asphaltene Problematic Reservoir, Burgan Oilfield Kuwait
Al-Shammari, A. (Kuwait Oil Company, Kuwait) | Sinha, S. (Kuwait Oil Company, Kuwait) | Sheikh, B. (NAPESCO, Kuwait) | Youssef, A. (NAPESCO, Kuwait) | Jimenez, C. (Kuwait Oil Company, Kuwait) | Al-Mahmeed, F. (Kuwait Oil Company, Kuwait) | Al-Shamali, A. (Kuwait Oil Company, Kuwait)
Abstract The Burgan Marrat Reservoir is a challenging high-pressure, high-temperature carbonate oil reservoir dating back to the Jurassic age. This specific reservoir within the Burgan Field yields light oil, but it has a significant issue with Asphaltene deposition in the wellbore. Additionally, its well productivity is hampered by low matrix permeability. Addressing these challenges is crucial, and a successful acid fracturing process can not only enhance well productivity but also address Asphaltene-related problems. This study delves into a comprehensive methodology that was employed. The focus of well selection was on ensuring good well integrity and maintaining a considerable distance from the oil-water contact (OWC). The approach involved conducting a Multi-Rate test followed by pressure build-up to establish a baseline for understanding the reservoir's behavior, including darcy and non-darcy skin. The treatment design aimed at better fluid loss control and initiating highly conductive fractures in the reservoir. Specific measures, such as using suitable diverters and acid, were employed to maximize the length of the fractures. To validate the approach, a nodal analysis model was fine-tuned to predict how the well would perform under these conditions. The results post-stimulation were impressive. There was a substantial improvement in well production and flowing bottom hole pressure. In fact, the productivity index of the well increased significantly, representing a substantial enhancement in output. The pressure build-up test after the fracture demonstrated a linear flow within the fracture, indicating a successful treatment with a fracture half-length of approximately 110 feet and a negative skin, which signifies an improvement in flow efficiency. Furthermore, the treatment effectively mitigated the risk associated with Asphaltene deposition, a significant accomplishment given the historical challenges faced in this reservoir. This success can be attributed to an innovative workflow that incorporated a meticulous surveillance plan, a well-thought-out fracturing treatment design, and the application of advanced nodal analysis. Together, these components not only optimized the well's performance but also paved the way for the development of similar high-pressure, tight carbonate reservoirs. This approach not only enhances productivity but also ensures successful mitigation of Asphaltene-related issues, marking a significant advancement in reservoir engineering techniques.
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (15 more...)
Completion Design and Equipment Selection to Facilitate Operations in a New Deepwater Region
Giuliani, C. (BP Exploration, Aberdeen, United Kingdom) | Tahirov, T. (BP Exploration, Sunbury, United Kingdom) | Hou, W. (BP Exploration, Sunbury, United Kingdom) | Xiao, Y. (BP Exploration, Houston, United States of America) | Eissa, M. (SLB, Lagos, Nigeria) | Varghese, M. (SLB, Abu Dhabi, United Arab Emirates) | McKenzie, K. (Expro, Aberdeen, United Kingdom) | Roy, A. (BP Exploration, Aberdeen, United Kingdom) | Leng, M. (BP Exploration, Sunbury, United Kingdom)
Abstract Mauritania and Senegal are emerging oil and gas producers with new oilfield infrastructure being developed. However, exciting new Deepwater Opportunities are starting to be developed with a 4 well subsea production well program recently being completed in the Greater Tortue Ahmeyim (GTA) field. The operator, having extensive deepwater experience globally, and regionally, completed a thorough set of extensive completion design studies with a view to installing fit for purpose completions to match the reservoir and environmental conditions which included: Deepwater Wells (2,700m) Limited Oilfield Infrastructure and logistics Gas reservoir with risk of perched water / aquifer presence High-rate gas wells > 220 mmscf/day per well Multi-layer reservoirs Potentially weak rock / borderline sand control requirement Hydrate risks This paper will examine the approach to completion design to deliver effective completions with life of well integrity/performance while simultaneously addressing the challenges of opening up a new oilfield region. The completion selection process will be discussed in detail including the methodology whereby technical requirements for robust solutions in critical areas such as sand production risks and reservoir performance are weighed against more nebulous selection criteria such as in-region supplier capability (limited in a new region), desire for operational simplicity. Fit for purpose completion designs have been installed in the first phase of 4 wells and the paper will detail the lessons learned and insight around the effectiveness of the decisions made including: Sand control effectiveness of the Cased and Perforated Completion Performance of wireline deployed perforating with dynamic underbalance incorporated Impact of limited inventory in a new oilfield environment with minimal infrastructure Impact of well clean-up in multi-layer wells from reduced production rates due to surface equipment limitations Effective data acquisition in multi-layer reservoirs including PLTs, DFOS and PBU Hydrate management in a relatively low temperature gas reservoir in deepwater With the experience gained by Operator, the Partners and Service Companies completion design is already underway for the next phase of wells in 2025 with the desire to implement more complex Downhole Flow Control completions in highly deviated wells to address the subsequent challenge of multi-layer reservoirs with more aerial distribution. The design approach to meet this challenge will also be introduced in this paper.
- North America > United States > Texas (0.67)
- Africa > Senegal > North Atlantic Ocean (0.54)
- Africa > Mauritania > North Atlantic Ocean (0.54)
- Africa > Mauritania > North Atlantic Ocean > Mauritania-Senegal-Guinea-Bissau Basin > Block C6 > Greater Tortue Complex (0.99)
- Africa > Mauritania > North Atlantic Ocean > Mauritania-Senegal-Guinea-Bissau Basin > Block C13 > Greater Tortue Complex (0.99)
- Africa > Mauritania > North Atlantic Ocean > Mauritania-Senegal-Guinea-Bissau Basin > Block C12 > Greater Tortue Complex (0.99)
- (2 more...)
Unconventionally Hydraulic Fractured Wells to Develop a Tight Sour Oil Reservoir
Mandhr, Al Kalbani (Petroleum Development Oman) | Yong, Ouyang (Petroleum Development Oman) | Ameera, Al Harrasi (Petroleum Development Oman) | Saif, Al Jarradi (Petroleum Development Oman) | Dmitrii, Smirnov (Petroleum Development Oman) | Kifah, Al Tobi (Petroleum Development Oman) | Aida, Al Khusaibai (Petroleum Development Oman) | Tom, Lefeber (Petroleum Development Oman) | Al Ghaliya, Al Shabibi (Petroleum Development Oman) | Jose, Viota (Petroleum Development Oman) | Zuwaida, Al Saadi (Petroleum Development Oman)
Abstract Summary A field in the southern Sultanate of Oman producing from a tight salicylate reservoir is being studied to evaluate its development potential with unconventional hydraulically fractured vertical wells after initial results from two proof-of-concept wells were positive. The reservoir is more than 3,000 m deep, trapped in salt and over-pressured. It contains sour oil with H2S/CO2 contents of 1 and 2 mol%, respectively, and highly saline formation brine. Although the reservoir has good porosity, the formation is tight with micro-Darcy permeability. Of the eight producers present, two producers have been fracked unconventionally hydraulically with 6 and 15 stages, respectively. The study aims to develop such a field with unconventionally hydraulically fracked producers to mature commercial volumes and meet the value drivers of the project. Development of the field is intended to be phased, starting with the crestal area to reduce risk, and progressing to the flanks over time. The project went through several phases and milestones to explore project decisions and select the optimal options to meet the project's value drivers. The team was tasked with economically optimizing the number of wells, well placement and frac design, well material and completion, and developing a solution for halite scale precipitation. Frac parameters were first matched in Ghofer frac model to match frac job parameters for the two existing unconventionally fracked wells. Dynamic simulation models with frac models were used to match well test and Production-Log (PLT) data. These models were then used to generate production forecasts to support project decision-making and maximize value while ensuring project competitiveness within the company's project portfolio. To address halite scaling potential during frac fluid recovery, water samples were collected and analyzed for compatibility and scaling potential and to optimize a scaling mitigation strategy. The two unconventionally fracked wells produced longer fractures than the conventional wells and have shown to deliver greater economic oil rates. Sonic noise log and well test results demonstrate that guar-based gel produces thicker and shorter cracks. High-viscosity friction reducer (HVFR) produces thinner but much longer fractures. Unconventional fracs increase reservoir coverage by three times compared to conventionally fracked wells, resulting in a five-fold increase in oil recovery at higher pipe-head pressures. From these findings, the decision is made for unconventional fracs, cleaner HVFR frac fluid, and fracture conductivity damage of about 15-25%. The optimal unconventional frac design and well spacing were considered dependent and evaluated in combination. Key well design, completion, and material decisions were made considering production conditions to safely produce commercial oil. To reduce the outcome uncertainty and implementation risk while developing the field, multiple scenario trees were constructed, which were used to decide on the phased manner for field development. The study shows that well spacing and optimal number of wells should be studied with frac design. All decisions related to subsurface, frac technology and well design should be made in an integrated manner, considering the circumstances of the project to make optimal decisions.
- Asia > Middle East > Oman (0.34)
- Europe > Norway > Norwegian Sea (0.25)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.50)
- Geology > Mineral > Halide > Halite (0.44)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (3 more...)
Design for preventing or minimizing the effects of accidents is termed accidental limit states (ALS) design and is characterized by preventing/minimizing loss of life, environmental damage, and loss of the structure. Collision, grounding, dropped objects, explosion, and fire are traditional accident categories.
- South America > Brazil (1.00)
- Oceania > Australia (1.00)
- North America > Canada (1.00)
- (11 more...)
- Summary/Review (1.00)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- (3 more...)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.67)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.67)
- Transportation > Marine (1.00)
- Transportation > Infrastructure & Services (1.00)
- Transportation > Ground (1.00)
- (36 more...)
- South America > Brazil > Campos Basin (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Viosca Knoll > Block 786 > Petronius Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Mississippi Canyon > Block 392 > Appomattox Field (0.99)
- (58 more...)
Novel Candidate Screening and Successful Implementation of Stimulation in Screen Completed Wells to Double Production in Brown Fields – A Case Study from Offshore Malaysia
Anand, Saurabh (PETRONAS Carigali Sdn Bhd) | Mat Khair, Nusheena (PETRONAS Carigali Sdn Bhd) | Azhar B. Abu Bakar, Khairul (PETRONAS Carigali Sdn Bhd) | Madon, Bahrom (PETRONAS Carigali Sdn Bhd) | Kin Chun, Kok (PETRONAS Carigali Sdn Bhd) | M. Adib, M. Syamil (PETRONAS Carigali Sdn Bhd) | Rahim, M. Ikhlas (PETRONAS Carigali Sdn Bhd)
Abstract Majority of wells completed offshore Malaysia have downhole screens installed for sand and fines control. It is however observed that the PI of most of these wells drop multifold times within first few years of production. This paper illustrates the workflow with novel technique of screening such wells for stimulation to restore well production. This paper will also illustrate a few examples of actual implementation of the stimulation jobs and the excellent results from these jobs. Hundreds of strings operated by PETRONAS in Malaysia Offshore across various fields have some form of downhole screen (standalone or as part of the gravel pack) installed to control sand and fines. Although these completions remain effective initially, but water break through results in significant PI decrease. It has been established that the predominant cause of this decline is the screen or gravel pack plugging by the fines mobilized by water which is followed in many cases by deposition of inorganic or organic scales. A workflow was developed using data from existing digital production monitoring system to identify wells showing the plugging behaviour. The workflow used several factors such as liquid rate decline, GOR, water cut, reservoir pressure, artificial lift performance etc to shortlist a list of wells on which a detailed nodal analysis was applied to estimate gains assuming 70% skin reduction. The wells which passed the workflow and showed maximum benefit from stimulation were then grouped together such that a campaign-based execution could be done to optimize cost. Detailed customized stimulation recipe for each well was prepared and optimized well level operation program was prepared. Optimization such as using bullheading technique instead of using coil tubing in some cases was done. Stimulation treatment in 4 of the wells has been pumped successfully with excellent results and an estimated 1,000 bopd total gains. The post job oil rate is double the initial rate in many cases and even 200% more in some of the cases. Post job nodal analysis suggests up to 90% damage skin removal in these wells. Optimized operation program and campaign-based execution coupled with other cost saving measures implied that the payback time was less than 1 month. PDG data from one of the wells was used extensively to evaluate pre & post stimulation well behavior. The high damage skin in the screen completed wells is one of the most pertinent issues which leads to significant production loss in wells offshore Malaysia. This paper details a quick and robust method to identify such wells for stimulation. The results from these stimulation jobs on candidate wells are very encouraging particularly considering the economics of the jobs. Following the success of the initial jobs, many more candidate wells have been lined up for execution in near future.
- Asia > Malaysia (1.00)
- North America > United States > Texas > Terry County (0.40)
- North America > United States > Texas > Gaines County (0.40)
- Europe > United Kingdom > North Sea > Southern North Sea (0.40)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.48)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 186 > Field A Field > Silurian Tanezzuft Formation (0.97)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field A Field > Silurian Tanezzuft Formation (0.97)
- Africa > Middle East > Libya > Murzuq District > Murzuq Basin > Block NC 115 > Field B Field > Silurian Tanezzuft Formation > B27 Well (0.93)
Abstract This article's goal is to present some of the main flow assurance challenges faced by PETROBRAS in the Buzios oil field, from its early design stages to full operation, up to this day. These challenges include: hydrate formation in WAG (Water Alternating Gas) operations; reliability of the chemical injection system to prevent scale deposition; increasing GLR (Gas Liquid Ratio) management and operations with extremely high flowrates. Flow assurance experience amassed in Buzios and in other pre-salt oil fields, regarding all these presented issues, is particularly relevant for the development of future projects with similar characteristics, such as high liquid flow rate, high CO2 content and high scaling potential.
- North America > United States (1.00)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean (0.72)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Block BM-S-11 > Buzios Field > Guaratiba Formation (0.99)
- South America > Brazil > Brazil > South Atlantic Ocean > Santos Basin (0.99)
Challenges and Potentials for Sand and Flow Control and Management in the Sandstone Oil Fields of Kazakhstan: A Literature Review
Soroush, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Roostaei, Morteza (RGL Reservoir Management Inc.) | Hosseini, Seyed Abolhassan (University of Alberta and RGL Reservoir Management Inc.) | Mohammadtabar, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Pourafshary, Peyman (Nazarbayev University) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Ghalambor, Ali (Oil Center Research International) | Fattahpour, Vahidoddin (RGL Reservoir Management Inc.)
Summary Kazakhstan owns one of the largest global oil reserves (approximately 3%). This paper aims at investigating the challenges and potentials for production from weakly consolidated and unconsolidated oil sandstone reserves in Kazakhstan. We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves in Kazakhstan were studied in terms of the depth, pay‐zone thickness, viscosity, particle‐size distribution (PSD), clay content, porosity, permeability, gas cap, bottomwater, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, the geological condition, including the existing structures, layers, and formations, were addressed for different reserves. Weakly consolidated heavy‐oil reserves in shallow depths (less than 500‐m true vertical depth) with oil viscosity of approximately 500 cp and thin pay zones (less than 10 m) have been successfully produced using cold methods; however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical compared with the similar cases in North America. The complicated tectonic history necessitates geomechanical models to strategize the sand control, especially in cased and perforated completions. These models are usually avoided in North America because of the less‐problematic conditions. Further investigation has shown that inflow‐control devices (ICDs) could be used to limit the water breakthrough, because water coning is a common problem that begins and intensifies the sanding. This paper provides a review on challenges and potentials for sand control and sand management in heavy‐oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (1.00)
- North America > United States > California (0.67)
- Asia > Kazakhstan > Mangystau Region > Caspian Sea (0.28)
- Overview (1.00)
- Research Report > New Finding (0.92)
- Phanerozoic > Paleozoic > Permian (1.00)
- Phanerozoic > Mesozoic > Triassic (1.00)
- Phanerozoic > Mesozoic > Jurassic (1.00)
- (2 more...)
- Geology > Structural Geology (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- (4 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.92)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Sand Control > Screen selection (1.00)
- (25 more...)
Flow Assurance Challenges for China’s First Deepwater Gas Field Development in South China Sea
Lau, Lawrence Khin (China National Offshore Oil Corporation) | An, Kun (China National Offshore Oil Corporation) | Tang, Xian Di (China National Offshore Oil Corporation) | Luo, Fei Jian (China National Offshore Oil Corporation) | Yang, Yang (China National Offshore Oil Corporation) | Zhao, Wei Qing (China National Offshore Oil Corporation)
Abstract This paper elucidates the key flow assurance challenges for China’s first National Deepwater gas field development in South China Sea and the facilities design forming the overall flow assurance management strategy. The discussion covers early stage feasibility studies through current stage of project execution. In addition, the finding of flow assurance analysis serves as key input for start-up and commissioning guidelines as well as operating procedures. The development consists of a semi-submersible, with the Eastern and the Western loops spanning more than 40 km of Subsea Production System (SPS). Due to long subsea tiebacks, integrated flow assurance analysis is rolled out to ensure comprehensive risks analysis and active risks management. In particular, key challenges associated with typical Deepwater characteristics such as high pressure and low temperature are actively managed. With design water depth of more than 1500 m and more than 10 Deepwater subsea production wells, robust flow assurance management strategy is required from early activities such as well unloading, well test, pre-commissioning, first gas, through late life decommissioning. Integrated approach is implemented for overall system thermohydraulics analysis, which is used as basis for key flow assurance assessments, including but not limited to management strategy for hydrate, scales, erosion, and slugging. Detailed management strategy and philosophy are discussed in the main body of this paper. Overall chemical management strategy, for instance, is fully optimized to reduce Health, Safety, Security and Environment (HSSE) impact, coupled with sufficient safety margin to ensure minimum downtime. Through integrated flow assurance analysis, all key risks are identified and actively managed. This shows the importance of integrated flow assurance approach to ensure overall project safety and integrity. More importantly, overall optimization can be successful rolled out when the field is in production. This serves as a positive lesson learned for future Deepwater development in South China Sea.
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (1.00)
- (4 more...)
Summary A successful rigless subsea stimulation was executed during 2018, with the intervention performed on three target wells offshore of Sabah Malaysia, at a water depth of approximately 1400 m (4,593 ft). Significant changes in reservoir performance prompted an acid‐stimulation and scale‐squeeze treatment, designed to remedy fines migration and scaling issues within the well and production system. Treatment fluids were delivered subsea by an open‐water hydraulic access system, using a hybrid coiled tubing downline (HCTD). Access to the subsea trees was enabled by a novel choke‐access technology, allowing for a flexible, cost-efficient, and low‐risk intervention. The intervention system was installed on a multiservice vessel, with the downline deployed via the vessel moonpool. A second support vessel was used as required to provide additional fluid capacity without disturbing primary intervention operations. This enhanced the flexibility of the operation, accommodating potential changes in the treatment plan without impact to critical path‐stimulation activities. The full intervention was delivered as an integrated service, with all elements supplied by a single provider, via one contract. An established network of in‐house equipment, expertise, test laboratories, and operational bases supported the planning and execution of the project. This was complemented by select external providers for vessels, remotely operated vehicle services, and other specialist contractors. The challenges faced during execution included completion of a comprehensive treatment fluid test program, importation and logistics of equipment from around the globe, and managing operational risks, all within a condensed timeline to satisfy a brief intervention window. A collaborative solution was developed that combined the resources of the service provider, inclusion of performance-based elements within the contract, and delivery of an efficient and flexible well-access technology that supported rapid mobilization and alleviated operational risk. Post‐stimulation well testing confirmed an average increase in oil productivity of 86%, with a corresponding productivity‐index factor gain of 3.4. These results confirm the appropriateness of open‐water hydraulic access using coiled tubing (CT) for performing cost‐effective stimulations on complex subsea wells.
- Asia (1.00)
- North America > United States > Texas (0.46)
- North America > United States (0.89)
- Europe > United Kingdom (0.89)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well Intervention (1.00)
- (5 more...)
Acidizing Combined with Heat Generating System in Low-Temperature Dolomitized Wax Damaged Carbonates
Folomeev, Aleksey Evgenyevich (RN-BashNIPIneft LLC) | Magadiev, Azat Failievich (Bashneft-Dobycha LLC) | Khatmullin, Arslan Rustemovich (RN-BashNIPIneft LLC) | Taipov, Ildar Azatovich (RN-BashNIPIneft LLC) | Vakhrushev, Sergey Aleksandrovich (RN-BashNIPIneft LLC) | Galiev, Timur Railevich (RN-BashNIPIneft LLC) | Mukhametov, Flyus Khanifovich (RN-BashNIPIneft LLC)
Abstract The article demonstrates the results of experimental and field studies of the thermal foam-acid treatment technology with the use of water solutions of heat and gas generating system. The potential temperature of the heat-generating reaction upon mixing of agents was estimated in laboratory conditions and the physical and chemical properties of acid solutions were determined. A series of filtration experiments was conducted on treating dolomitized core samples with a basic hydrochloric acid solution.The constant of the rate of reaction between the basic acid solution and dolomitized carbonate rock was determined based on the experiment results. The article provides a brief analytical overview of world experience of the thermochemical treatment of the bottomhole area. The technology selected for the tests called thermo-foam-acid and implies the step-by-step injection of water heat and gas generating solutions with an addition of surfactants and an initiator into the bottomhole area. The heat-generating reaction is accompanied by the generation of a large amount of heat, gases and hot foamed acid. Heating melts high molecular weight oil compounds, washes oil sheen from rock surface and increases the speed of its dissolution with hydrochloric acid. This foam acts as a diverter for the next portion of active acid and prevents undesired stimulation of high-permeability interlayers and fractures. Surfactants in the acid solution increase its ability to penetrate pores and microfractures. The physical modeling of a thermal foam-acid treatment has been performed. Arlanskoe (Kashirskian-Podolskian deposits) and Nadezhdinskoe (Famennian stage) fields where carbonate formations are characterized by high and increased oil viscosity, low reservoir temperature, fractured and dolomitized reservoirs were selected as a site to perform field tests. Well operation at these formations is complicated by the precipitation of asphaltenes, resins and paraffins in the bottomhole area. Solution injection parameters were recorded during treatments based on this technology. The technological efficiency of this treatment was confirmed based on bottomhole pressure and temperature changes during injection operations. Technology efficiency was analyzed and the well flow rate was monitored based on the field test results. The main stages of this work are shown in Figure 1.Figure. 1: Project stages
- Asia (1.00)
- Europe > Russia > Volga Federal District (0.46)
- Europe > Norway > Norwegian Sea (0.44)
- (5 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- South America > Brazil > Bahia > Reconcavo Basin > Dom Joao Field > Sergi-Água Grande Formation (0.99)
- South America > Brazil > Bahia > Reconcavo Basin > Dom Joao Field > Sergei Formation (0.99)
- Europe > Russia > Volga Federal District > Bashkortostan > Volga Urals Basin > Arlanskoye Field (0.99)
- (12 more...)