The world's energy consumption has risen geometrically over the last three decades due to advancement in technology. In response to this ever increasing rising demand, other sources of energy have been explored. Reports show that fossil fuels (crude oil and natural gas) continue to take the lead despite these efforts. Hence, the Oil and Gas industry has put in a lot of technical measures to meet up with this high energy demand. Many works have been done on how to increase reserves and ultimately increase recovery but little has been achieved in this area. Therefore, a more reliable, efficient and effective way of enhancing recovery is necessary to make headway in countering this challenge. This research seeks to provide the feasibility of enhanced oil recovery (EOR) projects using high level data mining technology in the African Oil Producing Regions.
Data mining is a process which finds useful patterns from large amount of data. Data analysis process involves data exploration, pattern identification and pattern deployment to make accurate judgement necessary for EOR investment decisions. It provides a significant reduction in the level of uncertainty when compared with other existing techniques. In our concept, artificial intelligence and genetic algorithm was employed and recommendation made.
Results show that data mining technique is a robust tool for making EOR investment decisions, right from the early life of a field. Thus, this concept makes it more economical to execute EOR projects with lower level of uncertainties. Marginal fields can also be invested upon using data mining techniques.
Oil-production from EOR projects continues to supply an increasing percentage of the world's oil. About 3% of the worldwide production now comes from EOR (Taber, et al, 1997). Efforts to increase reserves and ultimately production of petroleum to meet global energy demands have been on the rise for decades. Various methods of improved oil recovery have been employed at different world's petroleum production zones and the results are encouraging in most cases. EOR projects are successful when their candidates are chosen based on standard criteria for execution and right practices are adopted.
To make investment decisions on EOR projects, economic evaluations need to show fine prospects. Especially at zones such as the Niger Delta Basin in Nigeria where there are light crudes, a determinant is necessary to predict approximately how much an EOR method will produce. Since data are available across board on production history around the world, data mining technique has the capacity to analyse such data to predict the performance of prospective EOR methods.
Data mining is an analytical process designed for extracting or exploring hidden and predictive information from large databases which may be business or market related. It can also be described as the process of searching for valuable information in large volumes of data. Data mining is relatively a powerful new technology with great potential to assist companies focus on the most important information in their data warehouses (Olumoye, 2009).
A sandstone reservoir (SA) is the main producer reservoir in offshore Khafji oil field. This field has been producing since 1959. However, for time being, some wells suffer from excessive water production especially in old vertical wells. In addition, early water breakthrough in vertical wells is mainly due to high permeability streaks and unfavorable mobility ratio.
Therefore, controlling water production is a challenge for reservoir management team work in Khafji Joint Operations (KJO) because there are several different explanations for the water sources in SA sandstone reservoir. These sources could be one or combination of edge water movement and flow behind casing. This phenomena can occur due to high permeability streaks, and conductive channels or/and faults.
To sustain the KJO Maximum Sustainable Capacity (MSC), reservoir management in KJO should apply optimum development scenarios for reducing the water production utilizing several and effective water shut-off techniques due to production facility bottlenecks. Converting the old and high water production vertical wells to horizontal and lateral wells which have shown a high rate of success in terms of conducting better technique and scenario to retrieve and bring these wells into production with low water cut. The approaches included also reducing the choke size, cement jobs to shut-in watered out intervals and adding new perforations or re-perforating oil productive intervals. Several successful field cases have been applied in SA reservoir which resulted to high oil production with low water cut. This paper discussed more details of lessons learned and applied techniques to control excessive water production from oil wells and comparison in selecting them for applying optimum applicable techniques.
The results of water management techniques and scenarios to retrieve the wells are analyzed and discussed in this study. Reasons for conversion, directions, diagnosis, selected intervals, simulation results analysis, lessons learned, challenges and conclusions were addressed in this paper.
Reservoir management has now matured to the point where great emphasis is placed on working as a crossfunctional team, involving all technical areas, management, economics, legal, and environmental groups(1-10). This type of reservoir-management model has proved to be quite successful. Reservoir management practice relies on use of financial, technological, and human resources, while minimizing capital investments and operating expenses to maximize economic recovery of oil and gas from a reservoir. The purpose of reservoir management in Khafji reservoirs is to control present and future operations on the basis of information, facts, and knowledge which become crucial. This is because Khafji reservoirs are producing for more than 50 years, and become mature oil reservoirs. Such work needs better understanding of the reservoir drive mechanics, reservoir heterogeneity, shale continuity, vertical and horizontal permeabilities. However other reservoir and production issues should be considered such as types of suitable artificial lift systems and future prediction scenarios involving secondary and/or tertiary recovery techniques.
The carbon dioxide (CO2) sequestration and storage in aquifers and depleted oil and gas reservoirs is eminently a feasible solution to provide substantial cut in overall emission into the atmosphere. The current need is to understand the factors affecting the CO2 sequestration potential and capacity of particular formation/reservoir.
The purpose of this study is to investigate the CO2 storage in carbonate reservoir rocks under different conditions of pressure and temperature. Two groups of experiments were undertaken including; (1) investigating the CO2 solubility under different brine salinities, and different pressure and temperature conditions, and (2) studying the effect of CO2 storage time interval on porosity and permeability of carbonate reservoir rocks. Core storage experiments were undertaken using actual and similar core samples saturated with 25,000 ppm NaCl brine. The potential of the CO2 storage capacity and variations in porosity and permeability are evaluated and quantified.
The results showed that solubility of carbon dioxide decreases with increase in brine salinity and/or temperature. The increase of pressure causes a decrease in carbon dioxide solubility. In addition, the effect of temperature on carbon dioxide solubility diminishes above 120 oF and 4,000 psi pressure. The results also indicated that storage of carbon dioxide increases the petrophysical properties of porosity and permeability of carbonate rocks when the storage period is more than 150 days. On the other side, the CO2 storage for short time < 7 days causes reduction in porosity and permeability of carbonate reservoir rock.
The application of the attained results of this study is expected to have good impact on design storage process of carbon dioxide, validation of developed mathematical models, and improving our understanding of the process.
El-Morgan Field was discovered in 1965 and is located offshore in the Gulf of Suez (GoS) approximately 160 miles south of Suez, Egypt. Peak Production was approximately 300,000 BOPD within only three years. El-Morgan is considered one of the giant fields since its STOOIP is estimated to be approximately 2.689 billion BO with an ultimate recoverable reserve around 1.439 billion BO. Over its history, more than 250 wells were drilled. Currently, 179 wells are operating (125 producers & 54 Injectors).
El-Morgan is considered highly sophisticated field due to reservoir heterogeneity (Kareem reservoir), moderate stratification, limited aquifer support, high bubble-point pressure, low-permeability layers and its friable sand. Due to the high bubble-point pressure and high initial-rate (Pi=2,990psi & PB=2,269psi), the bubble-point pressure was encountered early in the field resulted in using peripheral injection to support reservoir pressure. In addition the reservoir heterogeneity while injecting peripherally, it is believed that significant oil reserves were being bypassed and were potentially unrecoverable.
This paper presents an integrated approach to optimize the development for a complex field from both subsurface and operations views. It also shows studies conducted to maximize the asset value, explains how the development strategy have been revised over time, to augment oil ended by using an EOR method nowadays (BrightWaterTM). All of these studies are coupled to the economical calculations.
Managing giant fields with a significant potential is very important since each incremental 1% in RF will increase the ultimate recovery by tens of millions oil barrels. Also through this paper you will assure importance of certain reservoir evaluation tools and how you can optimize them to increase ultimate recovery factor. Paper is an excellent example for reservoir management that resulted in more than 52% primary RF.
Zuo, Julian Y. (Schlumberger) | Mullins, Oliver C. (Schlumberger) | Elshahawi, Hani (Shell) | Ramaswami, Shyamalan (Shell) | Dong, Chengli (Shell) | Dumont, Hadrien (Schlumberger) | Zhang, Dan (Schlumberger) | Ruiz-Morales, Yosadara (Instituto Mexicano del Petroleo)
Understanding reservoir complexities such as compartmentalization and compositional gradients early on is crucial for optimal field development, especially in deepwater environments. Downhole fluid analysis (DFA) measures composition, gas/oil ratio (GOR), density, optical density (linearly associated with asphaltene content), and fluorescence intensity. Based on the Yen-Mullins model of asphaltene science and DFA measurements, the industry's first predictive asphaltene equation of state (EOS), the Flory-Huggins-Zuo (FHZ) EOS has been developed. It has been successfully used to estimate asphaltene concentration (optical density, OD) gradients and help predict reservoir connectivity - subsequently proven by production data. This provides an advanced reservoir evaluation tool, which reduces uncertainty in reservoir characterization.
In this paper, DFA and the FHZ EOS were used to analyze a couple of case studies: The first deals with a black oil column with a steep asphaltene gradient; the second and third deal with a light (near critical) oil with a large compositional gradient. For the black oil column, detailed analysis of recently available pressure data suggests that this oil column is disconnected from the aquifer and from the regional pressure regime. For the light oil columns, the delumping technique (Zuo et al., 2008) was used to obtain compositions from the DFA data which compared well with gas chromatography data. The cubic EOS was applied to describe the large variations observed in composition, GOR and density. The obtained results were also in good agreement with the measurements. Because of very low optical absorption in this light oil column, the FHZ EOS was employed to analyze the fluorescence intensity gradient, which is correlated with a fraction of heavy resins. The FHZ EOS has been successfully extended to light oil with very low optical absorption but a large fluorescence intensity gradient for the first time. The results show that the heavy resin is molecularly dispersed in this light oil column, and the GOR gradient creates the fluorescence intensity (heavy resin) gradient via the solubility term of the FHZ EOS. The equilibrium heavy resin distribution suggests this oil column is connected, which is also proven by other log and production data with the latter indicating a variable mix of the end members.
In addition, tar mat formation is reviewed showing that the physical chemistry approaching embodied by the FHZ EOS and the Yen-Mullins model can treat asphaltic fluids as well. In particular two fundamental methods of tar mat are identified; one mechanism is from gas addition, where solution gas increases causing tar mat formation with a discontinuous increase of asphaltene content at the oil-tar contact. The other mechanism is by asphaltene addition, where the concentration of asphaltene is increased beyond its solubility limit. This type of tar yields a continuous increase in asphaltene concentration at the oil-tar contact. Note that in contrast to other putative explanations, water plays no role in either of these mechanisms for tar mat formation.
Reservoir saturation monitoring, through cased wells, usually is the main key factor for proper reservoir management and recovery optimization in the cases of developed and mature oil fields. Thermal decay time tool (TDT) has been the main technique used for monitoring the inter wells water saturations in developed reservoir. One of the main problems that encountered while using TDT log is the reservoirs with low formation water salinity, this problem may also appear in reservoirs that are supported by water injection projects, in which the formation water is diluted by the injected water. This problem has been solved by combining TDT technique and cased hole formation resistivity tool (CHFR).
The ability to detect and evaluate bypassed hydrocarbon and monitor fluid movement in sandstone reservoir is a vital question to improve production and increase recovery. It is difficult to interpret the TDT data in reservoirs with low-salinity sandstone formation water. This problem cannot be solved because TDT measurements depend on the salt content in formation brine. Instead the cased hole formation resistivity tool (CHFR) is proposed to overcome the limitations associated with pulsed-neutron tools. This paper presents case studies of pay zones-saturation monitoring obtained from TDT and CHFR logs recorded in wells in mature sandstone reservoir which suffers from high water cut. The results are referenced to open-hole resistivity logs to monitor the vertical movement of reservoir fluids. It was found that water saturations calculated from CHFR logs are more accurate than TDT log in most cases. Water shut-off remedial action to manage water production from producing sections in the studied wells has been much more successful based on CHFR / TDT logs than the proposed remedial action based only on TDT data interpretation.
Fractured reservoirs are more complicated than matrix reservoirs and they do require to be evaluated correctly. Information on the accurate characterization of fault zones and on the way in which faults and fractures affect fluid flow are needed. In this study, a 3D multi component and multi directional deterministic operator is designed and developed to detect sub-seismic faults from seismic data that converge at a point, to map conduits in naturally fractured reservoirs. This operator is cubic and composed of nine symmetrical two dimensional plane templates. They are designed to search all possible directions and angles, to detect and match any two sub-seismic faults that meet at its center. It covers seventy two detection directions, and angles range from 22.5° to 157.5°. Three binary decisions are performed with each of the nine symmetrical planes. the first is for detecting a sub seismic fault at a point, the second is for evaluating a linear arrangement of these points and the third is to verify if two linear arrangements exist on the same plane.
The case study is presenting conduits maps to demonstrate the behavior of three different sub-seismic fault size ranges. The conduits intensities vary within and for each formation. They are minimal to absent in reservoirs top seal. This technique detects only small scaled faults. It can't detect primary sedimentary structures and random noises. It provides an output related to the variation of dual porosity and permeability and can be considered a supporting input for more realistic reservoir simulation. This technique helps determine the effect of natural fractures in the reservoirs as early as possible so that the evaluations and planning can be done correctly from day one. It is a reliable tool for reservoir top seal fracturing evaluation, sweet spots in fractured reservoirs delineation and potential compartments identification.
A predictive knowledge of fault zone structure and transmissibility can have an enormous impact on the economic viability of exploration targets and generate considerable benefits during reservoir management. Understanding the effects of faults and fractures on fluid flow behavior and distribution within hydrocarbon provinces has therefore become a priority. To model fluid flow in hydrocarbon reservoirs, it is essential to gain a detailed insight into the evolution, structure and properties of faults and fractures. Fault zones can have highly complex geometries, with strain being accommodated not just on a single fault plane but within a complex array of faults known as a damage zone.
Al-Saeedi, M. J. (Kuwait Oil Company) | Al-Enezi, D. (Kuwait Oil Company) | Sounderrajan, M. (Kuwait Oil Company) | Saxena, A. K. (Kuwait Oil Company) | Gumballi, G. K. (Kuwait Oil Company) | McKinnell, D. C. (Total)
Kuwait Oil Company has embarked on an ambitious project of drilling development wells to exploit the Najmah-Sargelu and Middle Marrat reservoirs at depths of 14,000 to 17,000 ft. These Jurassic formations consist of layered shales and limestones, which can be heavily fractured and highly pressured. The wells drilled to these prospects are very challenging because of HPHT conditions, narrow pore/fracture pressure windows, and high levels of H2S and CO2.
During drilling and production high concentrations of H2S and CO2 have been recorded. Given the strategic importance of these gas prospects, a study was undertaken into the metallurgy of materials planned for these production wells. With high levels of toxic gases and HP conditions, the severity of sour service was evaluated to be within the most severe area when referencing NACE standards. Dependent on well bore fluid and onset of any water production, Stress Corrosion Cracking (SCC) and Weight Loss Corrosion could occur leading to material failure and lost production. After this study, the use of CRA materials was recommended in future wells to counter these challenges.
The application of CRA for down hole tubular and surface wellhead equipment has gained wide acceptance in sour fluid service in recent years especially in HPHT wells. CRA usage has increased to; eliminate intensive corrosion inhibition programs, reduce maintenance costs and enhance safety. Considering the key parameters influencing corrosion properties of CRA (temperature, partial pressure of H2S and CO2, pH environment, chloride concentrations), it was decided to specify the use of 28 Cr CRA material for these Jurassic gas wells. This paper will discuss the initial study of the material metallurgy, the well design, the specification of tubulars and wellhead, special procedures necessary to run these exotic materials plus details of actual operations in the first wells.
Kuwait Oil Company has commenced an integrated field development project to produce gas and light oil from the Jurassic formations in the North Kuwait oilfields. This project is a major venture with currently nine deep rigs employed to drill around 120 wells to cover a nominal production of 1,000 MMscf/d of gas and 350,000 bbl/d of light oil. The wells target the Najmah-Sargelu and Middle Marrat formations in the Jurassic horizon, at depths of 14,000 to 17,000 ft. These zones consist of layered shales and limestones, which can be heavily fractured and are highly pressured.
Given the strategic importance of the North Kuwait Jurassic gas project and the related HPHT deep gas exploration well program, an extensive study was carried out to review the metallurgy of the materials used in well construction. The study targeted the main items which would be exposed to some degree of sour service; tubulars, hangers, packers, completion equipment and wellheads. For tubulars, the study concentrated on the production casings and completion tubing. The material review and recommendations were made considering the Sulfide Stress Cracking (SSC), Stress Corrosion Cracking (SCC) and any other type of corrosion which could occur for the intended applications over a well life of 12 - 15 years.
The severity of sour service was evaluated with reference to the latest NACE MR-0175/ISO 15156 severity diagram, and all proposed operating conditions were found to be within the most severe area for sour service.
Facilities sand management is tasked with the goal of ensuring sustained hydrocarbon production when particulate solids (i.e. sand or proppant) are present in well fluids, while minimizing the impact of these produced solids on surface equipment. Particle size and total concentration of formation sand or proppant determines their net effect on production and the resulting operability of surface facilities. Conventional sand management control focuses on sand exclusion from the wellbore, either by production limits or completion design. Completions may adversely affect inflow due to skin buildup and both controls impede maximum hydrocarbon production. Alternatively, co-production of fluids and solids, with subsequent sand handling at surface facilities, is an inclusion paradigm that allows sustained hydrocarbon production. Produced solids are removed at the wellhead upstream of the choke using fit-for-purpose equipment. This methodology allows for increased or recovered hydrocarbon production, while their removal upstream of the choke protects facilities operations.
A description of the design, performance, operation, and effect on production rate is provided for sand inclusive production through application examples in the Caspian Sea, Indonesia, and South China Sea. Specific reference is given towards wellhead desanding, which forms the greater part of this approach, and has expanded from the first field installation in 1995 in the UK to every major oilfield producing region. Implementation of dedicated facilities sand management technology has resulted in increased hydrocarbon production from sand producing wells, extension of well life on marginal fields, and re-start of shut in wells.
The first industry-wide workshop to address solids handling from downhole generation to topsides disposal inclusive was held by the SPE Gulf Coast Section in April, 2002 in Houston, TX. This workshop was entitled Facilities Sand Management: Getting the Beach out of Production. This workshop hosted speakers to discuss sub-surface sand management, sand monitoring & measurement, flow-line erosion, facilities design, separation, solids cleaning, disposal, and slurry injection. Attendee response showed that the leading sand handling needs were subsea separation and disposal, subsurface-surface integration, and increasing the robustness of surface facilities to handle sand production.
Several production companies have started to integrate facilities sand management into their sand control portfolio. Equal merit is given to sand separation at the surface facilities and completion technologies to determine which approach provides sustained hydrocarbon production. Gravel pack and screen completions have a well-established installation and operating base and form the majority of conventional sand control. While controlling sand production in numerous wells, these techniques may still pass sand of <50-125 µm diameter under normal operating conditions, and this sand interferes with facilities operations. In the case of a completion failure, the sand amount and particle size may increase rapidly leading to production restrictions or damaged equipment.
The necessity for a technology that could protect surface facilities equipment (i.e., chokes, flow lines, pumps, separators, valves, etc.) in cases of completion failure, open hole completion, or rapid unplanned sand production led to the development of the multiphase desander for solids removal at the wellhead. Since the implementation of this technology 18 years ago, the wellhead desander has found repeated use as a service tool for the collection of solids during workover or well test operations and as a permanent unit operation to protect surface facilities equipment. Implementation of fit-for-purpose sand handling technology into surface facilities has enabled sustained operations in cases where previous actions were to shut in wells, limit hydrocarbon production, or suffer lengthy and costly maintenance outages.
Shape Factor and drainage area in hydrocarbon reservoir are of the necessary and influencing factors on evaluation and optimization of drilling operation in oil fields. There are numerous methods to calculate the reservoir average pressure in conventional and sandstone reservoirs in that shape and drainage area of the reservoir are of important variables. On the other hand, these relations especially set for sandstone reservoirs and have limited usage in natural fracture reservoirs. This research demonstrates an approach to figure out shape factor and drainage area of wells in carbonated and naturally fractured reservoirs in all pressure and fluidity conditions. To assess this goal, results of well testing are carried out both for development of inflow performance curve and finding the drainage area. To make sure about the validity and preciseness of this method, it was investigated against the data from a well in a natural fracture field and the results were compared with those of other methods. Results dictated that the new approach can provide us with more precise and correct routes for the shape of the well in naturally fractured reservoirs. The suggested approach in this research needs production test data that has been optimized by well testing data for naturally fractured reservoirs. Additionally, this approach implemented to the draw down test and Tiab direct technique which is related to Warren and Root solution. What's more, this approach is reliable for all vertical wells in naturally fractured reservoirs (NFRs) with accessible production test data and well testing.