bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study: Integrated Study for Assessing Production Enhancement from a Matured Large Carbonate Reservoir in Kuwait
Authors: Al-Maraghi Eisa , Nair Cholamcottu V. G. 
Published: June 2014

Abstract
An integrated study has been conducted to build a reservoir management tool to evaluate feasibility of enhancing the production and maintaining the plateau rate long for the Umm Gudair field, a large carbonate reservoir located in Kuwait and the Partitioned Neutral Zone. A comprehensive data gathering campaign was made during initial phase of infill drilling and an appreciable volume of rock and fluid data were obtained which assisted the geoscientists and engineer in developing an improved static and dynamic model.
A team of geoscientists developed a complex geostatistical geologic model, considering 3D seismic, large suit of log data from 170 wells, core description of about 6000 ft of cores collected from 31 wells, etc. The detailed fine scale geologic model was built using one of the latest software and upscaled using a hybrid procedure involving statistical methodologies and upscaled models were sense-checked through streamline simulations to ensure that the selected simulation model preserves the features of the finescale model. The simulation model was history matched with 45 years production and surveillance data.
An optimum development plan was developed meeting the Company's strategic production requirements and a scheme that would provide extension of the current peak rate for another 5 years was recommended along with the necessary facility modifications and contingencies to mitigate uncertainties in long term production scenario. This paper highlights the critical steps of building a comprehensive reservoir simulation model through integration of the geological studies, engineering and production data and application of the model for planning production enhancement with the current and modified surface facilities in accordance with the Asset's long-term production strategy.
Fracture Acidizing of a HTHP Exploratory Well in Deep Carbonate Reservoir: A Case Study
Authors: Al-Omair F. S. , Siddiqui M. A. , Singh J. R. , Manimaran A. , Liu Hai , Razouqi Maen 
Published: June 2014

Abstract
The Jurassic carbonate reservoirs in Kuwait are deep, characterized with extremely low porosity and permeability. The temperature of these reservoirs ranges between 250-300°F. High production from these types of reservoirs will be possible if the oil filled fractures can discharge into large connected fractures during drawdown. Hence, these reservoirs are well suited for fracture stimulation to be exploited properly.
Fracture acidization of a deep HTHP exploratory well producing from limestone reservoir was performed successfully without any operational problem. The well was drilled to a depth of above 16,000 ft using high density oil-based mud (OBM). The well was tested in three intervals out of which the middle section produced high API gravity oil with gas. Initially, the well flowed at low rates but little increase in production was observed after matrix stimulation with emulsified acid. Lack of flow channels in the matrix was indicated by the continuous increase in bottomhole pressure during long shut-in period with a consistent drawdown pressure of 8,000 psi.
The low production of the well was investigated using borehole image logs, mud logs, daily drilling reports and core examination study. The findings of the study combined with data of the offset wells prompted fracture acidizing treatment. The well was fracture acidized using emulsified acid due to which the oil and gas production increased by several folds. Prior to the main fracturing treatment a step rate test, using 2 wt% KCl brine with surfactant, was conducted to determine reservoir parameters such as fracture extension pressure, fracture closure pressure and instantaneous shut-in pressure.
The paper highlights the usefulness of old data in deciding and designing the fracturing treatment to enhance reservoir deliverability. Additionally, a procedural mechanism for the selection of stimulation techniques, acid or proppant, in deep limestone reservoirs is discussed in this paper.
Beyond the Damkohler Number: A New Interpretation of Carbonate Wormholing
Authors: Talbot M. S. , Gdanski R. D. 
Published: June 2014

Abstract
Optimizing matrix acidizing is important to obtain the most effective stimulation treatment. Finding the optimum flow rate has been the subject of many papers and several of those focus on finding an optimum Damkohler number. This approach finds a unique solution only for a given linear core aspect ratio. Additionally, the pore volumes to breakthrough at the optimum Damkohler number are different between different laboratories and only scale to a master curve. This paper bridges the gap between data sets from different laboratories that have been performed using different aspect ratios. This paper uses the approach of minimizing the pore volumes to breakthrough as a function of interstitial velocity. To use the Damkohler number, the reactivities of all the rocks would need to be known, and they are generally not available from published work. Therefore, temperature is used in this model instead of reactivity.
This paper analyzes many plain hydrochloric acid test results and takes into account differences in temperature, acid concentration, core aspect ratio, porosity, and permeability. Having obtained a global function to describe all the data, the data can be collapsed to form a master curve. From this master curve, one can predict the optimum pump rate given a set of experiments conducted on a given rock regardless of aspect ratio. The new methodology allows improved optimization of acid wormholing using linear core test data from various laboratories by taking into account acid concentration, core aspect ratio, test temperature, and rock morphology in a single mathematical description.
Optimization of Completion Interval to Minimize Water Coning
Authors: Tabatabaei M. , Ghalambor A. , Guo B. 
Published: June 2014

Abstract
Horizontal wells have been found not ideal in many cases for solving water coning problems due to premature water breakthrough. This promoted a revisiting of the optimization of completion interval of vertical wells in bottom water-drive oil reservoirs. This paper presents a new approach to determining the optimum wellbore penetration for achieving the maximum water-free production rate of vertical well.
After reviewing the mechanism of water coning and the deluge of extremely sophisticated mathematical models in the literature, a simple analytical model has been derived in this study for completion engineers to optimize their water coning wells. The new model estimates the maximum water-free production rate (critical rate) considering the effect of limited wellbore penetration on the oil productivity of the well. To maximize the critical rate, an optimum wellbore penetration into an oil zone has been determined theoretically. This analytical model shows that the optimum wellbore penetration into the pay zone is less than half the total oil zone thickness, depending on the radius of wellbore, radius of drainage area, and pay zone thickness. Finally, this paper provides a tool in form of a set of curves which can be used for determining the optimum completion interval to make this approach easy to use for practice.
Behavior of Flow Through Low-Permeability Reservoirs
Authors: Lei Qun , Xiong Wei , Yuan Jiangru , Gao Shusheng , Wu Yu-Shu 
Published: June 2014

Abstract
While pores and throats of low-permeability reservoir rock are very tiny, they have significant influence on flow behavior in those reservoirs. There may be large differences in throat sizes and their distribution in low-permeability formations, even though they have similar storage space and flowing channels. Equivalent radii of flowing throats for low-permeability reservoirs with similar permeabilities may be very different. Stronger liquid-solid interaction within finer pore throats having a large interface area and abundant hydrophilic clay tends to prevent water from flowing through.
This paper presents a systematic study of flow behavior in low-permeability reservoirs using (1) a constant-rate mercury injection test, (2) a nuclear magnetic resonance (NMR) core analysis, and (3) a seepage experiment. NMR results show that mobile fluid saturation in low-permeability formations is very different from that in normal reservoirs. In general, the less clay content and larger throat radii of the low-permeability rock, the larger the mobile fluid saturation. We conducted a series of seepage tests, with the results showing that at low velocity, the flow rate in low-permeability rock is not linearly correlated with pressure gradient, but rather is a function of pressure gradient. Based on experimental results, we propose a modified Darcy's law for describing the observed nonlinear flow phenomenon, which is implemented into a black-oil model simulator. Simulation results incorporating the nonlinear flow-behavior show that effective permeability near production and injection wells is higher, whereas the permeability further away from the wells is lower. Well performance predicted by the linear model overestimates production rates, while that predicted by the new, nonlinear model better matches the field production data.
Reservoir Management of the Gullfaks Main Field
Authors: Talukdar Saifullah , Instefjord Rune 
Published: June 2014

Abstract
The giant Gullfaks Main Field comprises Statfjord, Cook and Brent Formations of Early to Middle Jurassic. The reservoir is complex due to large number of faults and extreme permeability contrast ranging from several Darcies in the Tarbert to milli-Darcy in the Cook. The highly productive sands are poorly consolidated causing sand production problem. Reservoir fluid in some of the areas contains high H2S. Uncertainties associated with structures, degree of communication, extreme contrast in reservoir properties and effective control of sand and H2S pose a great challenge for reservoir management.
Despite the challenges, the recovery factor on Gullfaks Main Field is high. A total of 335 Sm3 of oil has so far been produced, which amounts to an overall recovery factor of 56% (60% in the Brent Formation). This high recovery factor is attributed to effective reservoir management. The management strategy involves conservation of reservoir energy, implementation of simple and advanced strategies, systematic and sustained collection of data, and continuous application of improved recovery technologies.
Conservation of energy is achieved through water and gas injection. Simple and advanced strategies include selective perforation of wells, sand control, zone isolation, multi-target wells, controlled drainage through DIACS technology, through-tubing drilling, etc. Data collection involves 3D and 4D seismic, core and well log, RFT/MDT pressure, PLT, RST saturation, well completion, production and injection, etc. Improved recovery techniques, studied and some of them implemented, consist of infill-drilling, water and WAG injections, polymer assisted surfactant flooding, microbial injection, CO2 injection, etc. The current IOR initiatives are meant to extend the production life of the field to 2030 and thus meet the ambition of recovering 400 MSm3 of oil.
This paper summarizes the reservoir management challenges, techniques and technologies applied to evaluate and monitor the reservoir performance, and the strategies to enhance oil production.
Sand Cleanout with Coiled Tubing: Choice of Process, Tools, or Fluids?
Authors: Li J. , Misselbrook J. G. , Seal J. 
Published: June 2014

Abstract
Cleaning sand from wellbores is a major part of the coiled tubing (CT) industry. The process is a function of multiple variables including fluid properties, flow velocities, hole size and deviation, pipe eccentricity, particle properties and fill penetration rate and wiper trip speed. It becomes even more challenging to successfully remove fill from wells with low bottom hole pressure (BHP) especially if the well is completed with smaller diameter production tubulars which reduce circulation flow cross-section and choke flow. The problem is further compounded by high deviation or horizontal well trajectories especially in large diameter wellbores.
Several cleanout options have been developed in the past, employing a variety of different approaches. CT or conventional jointed pipe often incorporates high circulation rates, special fluids, wiper trip, or reverse circulation mode to remove solids. Many of these conventional sand cleanout methods often apply excess hydrostatic pressure on the formation, resulting in lost circulation in low formation pressure reservoirs. The conventional solution to overcome excess hydrostatic has been to include nitrogen to reduce fluid density and thus lessen the hydrostatic head. Sand vacuuming technology combines a concentric coiled tubing (CCT) string with a downhole jet pump to remove fills without placing hydrostatic loads on the reservoir.
This paper reviews the individual sand cleanout systems and discusses the advantages and limitations related to each method. Compared with other processes, cleaning sand using a wiper trip has become the most common and efficient mehtod. However, it needs an appropriate pump rate and reservoir pressure to maintain a proper return flow rate to carry the sands to the surface. For a depleted reservoir and especially for horizontal heavy oil wells, a sand vacuuming system can be used to efficiently remove the debris without circulating nitrogen and without high pump rates. The main application for the reverse circulation technique is cleaning sand from large diameter wellbores and when the necessary pump rates for conventional "forward" circulation are not achievable. Fluids with high solids suspension capability (under shear conditions) may be an economic option when the debris cannot be removed from a large diameter deviated wellbores using more conventional, but lower cost, cleanout fluids. The venturi junk bailer is often used to retrieve larger material or junk which is typically not circulated out by any other methods. Field cases are provided, demonstrating how to select the proper cleaning method and how to efficiently remove sands from a wellbore based on both operational and logistical conditions.
Using Monobore Systems to Lower Completion Costs in Short-Life Wells
Authors: Chapman Walt 
Published: June 2014

Abstract
A large percentage of the wells completed today are classified as short life or harvest wells. Many of these would not economically feasible utilizing high end completion components, and methods. Mono-Bore wells can be a solution to this dilemma.
This paper will discuss several methods and case histories used to complete these wells. Systems discussed and presented in this paper demonstrate how considerable time can be eliminated which will lower the overall completion cost as well. Several methods will be discussed and case histories provided to substantiate the results and savings. Methods will include the following:
Disposable completions utilizing the minimal completion components. Cemented Mono-Bore's utilizing Cement tolerant components, and methods/procedures of completing these wells. Staged cementing completion designs for open hole mono-bores. Simple water injector completions utilizing new technology. Low cost gas well unloading Case histories of the methods above discussing the advantages, and disadvantages of each method.
Illustrations along with detailed procedures will be discussed to better understand how each completion method can address the numerous opportunities, and problems associated in well completion design. Case histories will be provided to validate the each method. What if technologies will also be discussed in order to gain insight on what the future holds for these low cost wells.
An Alternative Method in Determining Permeability in Fractured Tight Gas Wells Dominated by Either Linear or Bilinear Flow
Authors: Bachman Robert C. , Hawkes Robert V. 
Published: June 2014

Abstract
Pressure transient tests are routinely performed on wells that have been hydraulically fractured. During the build-up, wells typically exhibit linear or bilinear flow, depending on the fracture conductivity. For high permeability wells radial flow may also be evident. For low permeability gas wells, the time to radial flow can often be impractically long. As a result many pressure transient analysis (PTA) tests end before radial flow happens. Without radial flow a unique value for reservoir permeability cannot be determined. To compound the problem low permeability wells often do not flow before being stimulated, so that pre-fracture tests require very specialized testing procedures and are not always possible. Unfortunately permeability dominates the productivity index calculation and without a reasonable value for permeability, the resultant production forecast will be significantly off. Furthermore, the ability to diagnose the success or failure of the actual stimulation treatment without prior knowledge of permeability will be diminished. This paper will show a technique, called the matrix method, which significantly reduces the uncertainty in permeability estimation for such cases. The essence of the technique is to generate a plausible set of matches considering the build-up data only. Then one takes this group of solutions and utilizes additional data, namely the pressure and rate history during the drawdown period, to determine the best possible match of the drawdown data.
Improved Water Saturation Estimation Using Equivalent Rock Element Model and Application to Different Rock Types
Authors: Shang Bruce Z. , Hamman Jeffry G. , Caldwell Donald H. 
Published: June 2014

Abstract
The second Archie equation relates water saturation to formation resistivity index through a power function. This important relationship has been widely used to evaluate hydrocarbon saturation. However, many rocks don't obey this empirical rule. The best Archie fit to these data may not comply with physical bounds and create significant bias in the computed hydrocarbon saturation.
This paper develops a new method for water saturation estimation based on the equivalent rock element model (EREM) that has been demonstrated to work well for rock transport properties to the first order effect. EREM contains two orthogonal pore components, one parallel and the other perpendicular to the direction of transport. Pore structure efficiency is defined as the volume ratio between the two components. When pores contain conductive and non-conductive fluid phases, the pore structure efficiency for the conductive phase changes with saturation due to fluid and mineral properties and pore structure variations. The conductive phase may become discontinuous below a certain critical saturation due to pore structure, wetting characteristics, interfacial tension, etc. The proposed algorithm incorporates this critical saturation phenomenon and relates capillary pressure data with electrical measurements. Approximating the pore structure efficiency of conductive phase as a function of saturation, we formulated a theoretical relationship between resistivity index and water saturation.
For some rocks, additional conductive meachanisms may exist in addition to electrolytic conductivity, in which case the Archie's equation would not apply. Many proposed formulas can be found in the literature regarding non-Archie rocks, but each only works well for a particular type of rocks. This paper demonstrates that the EREM approach can account for the additional conductivity and work well regardless of rock type.
This new approach expands the applications of the equivalent rock element model. It has several advantages over existing methods. (1) The approach is based on a simple physical model that reflects the two main components in a pore structure and accounts for the first order transfer effect. This ensures compliance with physical boundary conditions and increases the predictiveness. (2) The innovative inclusion of critical water saturation avoids the underestimation of water saturation at low water saturations. It links electrical measurements with capillary pressure measurements and allows the two observations to cross-validate and complement each other. (3) The proposed method is demonstrated to match core measurements from different rock and pore types with a single model.
The Art of Mentoring as told by Both Sides of the Three Decade Old Struggle in the Petroleum Industry
Authors: Edwards J. T. , Woo G. T. 
Published: June 2014

Abstract
Along with the dramatic price changes in the petroleum industry including gas and oil, there is one resource that has been seriously overlooked and undervalued: experienced personnel in the field, including engineers and other technical specialties. The real challenge is how this lack of experience is overcome in the short term, rather than just waiting for the passage of time. The petroleum industry can make significant gains quickly by investing in true, on the job mentoring. It could mean the difference between success and failure. Companies could be focusing less on headcount, and more on effective and well organized mentoring programs.
The shifts in supply and demand over the past three decades have at times left many within the technical side of the industry barely holding onto their jobs or looking at other vocations in order to maintain employment. Hoping to ride out the waves of boom and bust, those with valuable experience are not passing on their knowledge at a rate that can sustain our industry. These trends have led many colleges and universities to back away from true Petroleum degrees. Now that a demand is increasing again, how can the voids be filled quickly in the field with qualified and well-trained personnel, while the slow process of ramping up academic programs begins?
The only way to fill the void is through hiring from other engineering fields along with the inclusion of like-minded individuals with technical backgrounds. But now that they have been hired and are on the job, how can we maximize their success? The answer is mentoring. This paper will present the case with a personal perspective as told by mentors in the petroleum industry on both sides of the struggle, spanning three decades.
Enabling Our Enabling Technologies: What will it take, and what is at Stake?
Authors: Mody Rustom 
Published: June 2014

Abstract
In September 2006, BP and Baker Oil Tools celebrated the installation of the world's first successful expandable monobore liner extension, an achievement that marked a major milestone for solid expandable tubular technology. A month earlier, Baker and Petrobras marked another collaborative milestone for flawless operation of an all-electric intelligent completion system in a deepwater field.
Expandable metal technology and intelligent completions are among current favorite topics of trade journal editors, conference program committees and industry analysts, because each has the potential to substantially increase well value. Yet, how will these technologies be used in five years: routinely throughout the industry, or only for niche applications? Both have been commercially available for at least 10 years, yet acceptance has been slow, despite industry pressure for their development. Although applications are expanding, each technology is currently applied in a very small percentage of wells drilled.
Why is technology uptake in the oil and gas industry slower than in other industries? How and why do we remain risk-averse? What role does "technology backbone" play? Why is operator-service company collaboration important, and how can we achieve it? And, what is at stake if we do not change?