bluuebunny/crossref_metadata_2025_split huggingface dataset:
Seeing Beyond the Frac: Integration of Hydraulic Fracture Mapping With Multi-Component 3D Seismic Data
Authors: Shemeta J. E. , Davis T. L. , Roth M. , Riley R. B. 
Published: December 2007

Abstract
The Colorado School of Mines Reservoir Characterization Project (RCP) has performed a multi-year study of the Rulison Field in the Piceance Basin, Colorado in cooperation with the Williams Production Company. Rulison is a gas field producing from the Williams Fork Formation, which is part of the Mesaverde Group and consists of stacked fluvial sandstones. Commercial production in Rulison depends on hydraulic fracture (frac) stimulation, typically multiple stages targeting sands and some coals in the lower section of the formation. During fracing, the induced seismicity was recorded using borehole geophones as part of the 2006 RCP field campaign at Rulison. 3D surface seismic surveys collected over multiple years at Rulison are being used to characterize the faulting and natural fracture distribution within the field. This paper discusses integration of the hydraulic fracture microsesimic mapping results with 3D seismic volumes, which provides insight into hydraulic fracture growth and geometry and additional information for short and long term reservoir management.
Multiple-Zone Completion in Marginal Production Wells
Authors: Pitrelli Guillermo , Giraldo Maximiliano 
Published: December 2007

Abstract
Concepts on well multiple zone completion systems applied in marginal wells in Los Perales Oil Field, located in the Gulf of San Jorge Basin, Santa Cruz province Argentina. The field is fully operated by Repsol-YPF.
The paper narrates the challenge and experience of completing three marginal production wells (LP-2384, LP-2354 and Hue.xp-10), using concepts on well zone isolation, flow control capability, production management and easy well access in future workovers. The field is characterized by a stratified reservoir which is created by changes in depositional condition therefore each layer has different rock properties and flow characteristics (fluvial type reservoir). Gas oil and water are being produced commingle from different layers. The traditional method used to avoid production of a specific layer was cementing the layer or leaving it below a drillable plug (type N-plug). Despite difficulties, three wells were completed based on these concepts:
LP-2354: Selective zone completions, allowing reservoir and production management of three different gas sand beds.
LP-2384: Selective isolation of gas and water sand layers. Oil zone was put into production, allowing for ultimate gas recovery using pulling rig and a wireline unit instead of a workover recompletion.
Hue.xp-10: Gas ultimate recovery increased with a rig less workover completion. Killing the well, thus damaging the formation, was avoided.
Each well completion and intervention was designed, based on a cost effective and fit for purpose, criteria. Different arrays of tools (straddle retrievable packers, side pockets mandrels, mandrel valves and tubing screens) were run into the wells.
The main enhancements were the following:
Cost-effective rig less workover. Higher artificial lift performance by avoiding commingled flow using multiple zone isolation (no gas pound on the pump, no unwanted producing fluids). Cross flow and formation damage prevention due to commingled production. Easy well access to increase gas ultimate recovery, using a pulling rig instead of a workover recompletion. Recompletion of gas wells by means of wireline conveyed casing guns and wireline setting packers without killing the well in order to pull down tubing string and therefore preventing formation damage.
A More General Capillary Pressure Curve and Its Estimation From Production Data
Authors: Gang Tao , Kelkar Mohan 
Published: December 2007

Abstract
Capillary pressure plays a very important role in naturally fractured reservoirs. The exchange of fluids between matrix and fracture is essentially dependent on capillary pressure expressed by the capillary pressure curve. Capillary force may contribute to the displacement process through imbibition process, or may oppose it in the drainage displacement process.
It is essential to represent the capillary pressure curves properly. Many capillary pressure correlations have been suggested in the literature. Capillary pressure data were normally measured using core data. However these methods suffer limitation due to the scale over which the data were collected. Therefore it will be very useful if the capillary pressure curve could be extracted from production data through the history matching process.
This paper presents a simple and generalized capillary pressure model which captures both the spontaneous and forced parts of the imbibition capillary pressure curve. In addition, the capillary pressure was estimated by the production data. The sensitivities of production data with respect to capillary pressure model parameters are required when the gradient-based optimization algorithm is used to minimize the objective function. How to calculate the sensitivities of the production data with respect to the capillary pressure model parameters is provided. By minimizing the objective function which describes the mismatch of the observed and simulated production data, the water-oil capillary pressure curves are estimated. All of implementations are incorporated into a commercial simulator (ECLIPSE) and iterated in the automatic history matching scheme. The method is validated using many synthetic cases.
Transient Analysis of Flowlines and Slug Catcher Level Control
Authors: Rezzónico R. , Carp A. 
Published: December 2007

Abstract
The feasibility of handling increased flow from an expanded gathering system with the existing slug catcher was analyzed.
Transient analysis simulations for the flowlines were conducted to determine the surge flow at the receiving facilities when changes in flow rates, restart operations and pigging operations occur.
Knowing the surge flow (inlet liquid flow) vs. time, the operating volume of the slug catcher and the drain rate (processing flow) to the plant, it can be determined if the existing slug catcher volume is big enough for handling the flow variations and the incoming slugs for different scenarios.
A PI level controller was proposed to control the level in the slug catcher. It was possible to find the tuning parameters (Gain and Integral Time) in order to keep the liquid volume within the desired levels, avoiding undesirable sudden drain rate changes that are difficult to handle in the process units downstream of the slug catcher. Several operating cases were analyzed and it was concluded that pigging cases, especially those for the lowest gas flow rates, produce the biggest slugs. A properly tuned PI level controller helps to optimize the slug catcher volume.
The conclusions of this study are applicable to Gas Oil Separation Plants.
Evaluating and Developing Tight Gas Reserves—Best Practices
Authors: Stotts Garth W. J. , Anderson David M. , Mattar Louis 
Published: December 2007

Abstract
Tight gas is becoming an increasingly important asset for petroleum companies. Proper reservoir evaluation and development planning is critical to the success of a tight gas play. To date, the "best practices" for evaluating tight gas performance have not been well defined, and many companies use unreliable or unnecessary methods. As a result, analysts commonly misinterpret (and incorrectly book) tight gas reserves. Furthermore, the development of tight gas reservoirs is often conducted inefficiently, either through over-capitalization (too many wells, too quickly) or ineffective recovery (overly sparse spacing).
This paper presents a straight forward and technically sound approach for evaluating and planning the development of tight gas reservoirs. The critical step in the process is proper identification of the dominant reservoir flow regime. Without this step, we cannot choose the correct analysis plot to use. The techniques detailed in this paper are designed for production data sets ranging from about 3 months and upward. The reservoir and production characteristics (permeability, xf, flow regime) are determined using pressure/rate transient analysis, as are the drainage region and its expansion rate. The resulting model predicts well performance and the rate of increase of accessible recovery over time. Superposition of the appropriate economic model and well constraints allows the analyst to identify a practical range of EUR values that is more reliable than that provided by conventional decline curves. This process can be applied to reserve evaluation as well as optimizing well spacing in the reservoir. The analysis is performed through interpretation of a diagnostic plot paired with an appropriate recovery plot (using well constraints and economics). It is validated using simulated and field examples.
Transient Flow in Discretely Fractured Porous Media
Authors: Izadi M. , Yildiz T. 
Published: December 2007

AbstractThis paper presents an analytical study of transient flow into multiple vertical wells producing from a porous media containing randomly distributed discrete fractures. The model may be used to analyze the production and well test data from tight gas sands and Austin chalk type reservoirs. Both vertical openholes and hydraulically fractured vertical wells are considered. Wells and fractures are randomly distributed. The model dynamically couples the multiple fracture flow models with an analytical reservoir flow model. The analytical model simulates pressure and pressure derivative characteristics of wells and flow distribution along and through both the natural and hydraulic fractures.The study shows that single or multiple isolated fractures yield negative pseudoskin factors in vertical wells near isolated fractures. The negative pseudoskin factor in unstimulated wells has also been observed in field tests. The negative pseudoskin factor is a function of fracture conductivity, fracture density, length, distance from the wellbore, and azimuth.Using the model, we demonstrate that the shape of pressure derivative is related to fracture distribution. However, the wellbore pressure derivative response is controlled by the fractures in the near wellbore region.The result of this study indicate that the conventional analysis, based on the double porosity model such as the Warren and Root model, to predict the storativity ratio of a naturally fractured system is not reliable. Also, the displacement between two semilog straight lines is not necessarily a good indicator of the storativity ratio.
Evolution of Stimulation Jobs, Block X, Talara Basin, Perú
Authors: Sánchez Luis , Palomino Daniel , Mercado José , Díaz Tomás 
Published: December 2007

Abstract
Peru has a great background in the oil industry; the first well in South America was drilled in Zorritos, located on the northwest coast of Peru, in 1863. Originally, the wells were completed in the shallower pays with cemented casing and using perforated liners in the productive areas. Production was driven by the natural energy of the reservoirs.
Around 4600 wells have been drilled In Block X and, currently, there are 2021 producing wells, with an average production of 6.4 bls./day per well. Hydraulic fracturing is required to produce them economically.
These works have been done since 1953, and continue up to the present applying available technical innovations. Initially, stimulations were carried out through hydraulic fracturing using diverse multifrac techniques, with crude oil as base fluid. In the 90's, oil was substituted for water as a base fluid for stimulations, to generate better fractures and increase recoveries.
In spite of the maturity of Block X and the high wells density, new alternatives were searched in order to continue operating economically, considering:
□ Re-fracturing wells, in intervals of higher pays (500-1200 ft.) with low initial fracture efficiency □ Use of low cost local market sand that will allow to obtain significant savings. □ Reduction of polymeric load in fracturing fluids ranging 15 to 25 lb/mgal. □ Evaluation of new technologies (ultra light support agent and visco elastic fluids) to improve well productivity.
In this paper a historical perspective as well as currently applied technologies for stimulation are reviewed, and related field results are presented.
Advanced Heated Annulus Drive Technology: An Emerging Technology Compatible with Directional Drilling to Improve Recovery from Tar-Sand Reservoirs
Authors: Wajid Ali 
Published: December 2007

Abstract
Petroleum industry is technology driven. Any new strategy which is economically feasible and promotes sustainable development of oil and gas resources while respecting human safety and the environment, is a welcome change. "Advanced Heated Annulus Drive Technology" is one such field of development to produce oil from subsurface tar sand/heavy oil reservoirs. In this paper the said technology has been discussed keeping in view the above mentioned factors (i.e. economics, safety and environment).
This technology is disclosed for producing viscous petroleum. The method employs a vertical and a horizontal well through the petroleum deposit. A combination of injection procedures, through the horizontal and vertical well, heats the viscous petroleum in the annulus around the horizontal well. Successive completion intervals are installed in the horizontal well to produce the heated petroleum. The petroleum is driven by a drive fluid passing through previously produced intervals.
This technique is the best of previously described techniques for the recovery of oil from tar sand reservoirs. Previous proposals for the recovery of significant percentages of the petroleum in place have required a large number of vertical wells at very close spacing. While in the present proposal, most of the vertical wells are eliminated thereby greatly improving the development economics.
Heavy oils are a major potential source of future reserve renewal for the petroleum industry. Access to these reserves demands innovative production techniques that are more competitive than those already known. "Advanced Heated Annulus Drive Technology" may be regarded as a competitive technology of current era, for tar sand reservoirs.
Stochastic Modeling and Uncertainty Analysis of Mature Fields
Authors: Campozana F. P. , Backheuser Y. , Antunes R. F. , Camoleze Z. 
Published: December 2007

AbstractNowadays two things are absolutely crucial in petroleum industry: (1) an integrated approach from seismic to reservoir simulation (history matching included) and (2) uncertainty and risk analysis. The first one ensures that the model is coherent with all types of data and the second one drives decision and quantifies risk. Current available hardware and software allow simulating stochastic models with statistical analysis of multiple scenarios. It is important to have a standard workflow that takes into account both aspects and can be applied to all projects. Although geophysicists may not be used to, it is important to include uncertainty analysis on the geophysical model too.A mature field located in Brazil is used as an example to illustrate the approach suggested above. The field has produced more than 20 million bbl of light oil and now a complementary project development is under study. Despite the amount of oil that has been produced, a significant geological uncertainty still remains. To provide the asset managers with a realistic range of possible outcomes of a project development, a thorough geological stochastic modeling was conducted. Four thousand models were generated considering the following varying parameters: reservoir structure, oil/water contact, porosity, net-to-gross, and initial water saturation. The models were ranked by VOIP and the distribution was sampled (P1, P2, … P100) to go through numerical flow simulation. Permeability uncertainty was introduced by considering two possible scenarios for each model, giving a total of 200 reservoir models. Dynamic data was compared to simulation results through an objective function and those models which gave results too far away from production history were discarded. The VOIP distribution was recalculated.From this new distribution, the P10, P50, and P90 realizations were picked to be history matched. After that, 27 models were generated through experimental design to consider the variation in the following parameters: (1) geological model, (2) relative permeability, (3) absolute permeability, (4) well productivity index, and (5) the number of wells to be drilled in the project development. The second and third parameters were kept constant in the vicinity of the producing wells so that all 27 models honored production data. A response surface model was generated by interpolation of the 27 flow simulations to obtain 10.000 outcomes for different parameter values. From these results it was possible to perform uncertainty analysis on the prediction.
Influences of Gamma Ray Irradiation on Thermal Decomposition and Petrophysical Properties of Carbonate Rocks
Authors: Shedid Shedid A. 
Published: December 2007

Abstract
Gamma rays are bursts of high-energy electromagnetic waves that are emitted naturally by some radioactive elements. Laboratory experiments were undertaken to assess the influences of gamma irradiation on thermal decomposition and petrophysical properties of carbonate rocks of aquifers and oil reservoirs. A constant gamma ray dose of 9 MGy was applied on identical calcium carbonate core samples, extracted from actual oil reservoir. The core samples were analyzed using thermogravimetric analysis (TGA), differential thermal analysis (DTA), infrared spectrum (IR) and scanning electron microscope (SEM) before and after application of gamma ray irradiation. The attained data was used to interpret thermal decomposition, phase transition and mechanical stability of calcium carbonate rocks. Furthermore the effect of gamma irradiation on pertophysical properties of porosity and permeability were studied experimentally for water and oil saturated carbonate rocks.
Chemical composition of the carbonate core samples was determined using titration method and its sulfur content was determined using precipitation method. Application of Differential Thermal Analysis (DTA) proved the purification of the used core samples. Chemical analysis indicated that the core ha 99.8 % calcium carbonate. The Infrared (IR) indicated that no chemical changes of irradiated core samples have been observed. The analysis using DTA and TGA indicated that gamma irradiation enhanced thermal decomposition of carbonate rocks of oil reservoirs. The obtained results indicated that calcium carbonate rocks are stable rocks. In addition, the gamma ray irradiation has been proven to have almost no effect on porosity and permeability of these reservoir rocks.
Applications of the attained results are expected to have real impact on deep understanding of rock stability, using gamma ray tools and measuring gamma ray levels in oil fields, and improvements in future interpretation of attained data from gamma ray measurements such as gamma ray log.
Optimization of Deepwater Drilling with Real-Time Operations
Authors: Hamed Walid , Bassem Ahmed , Gamal Medhat , Nafie Sherif , Oraby Moustafa , Waheed Arshad 
Published: December 2007

Abstract
The following-up of drilling operations in "real time" from a remote location has been on the wish list of some drillers for quite a long time. In recent years, this has become a reality with phenomenal advances in digital technologies, satellite communications, remotely controlled systems, and collaboration centers that allow locations in different parts of the world to follow up on an operation on a round-the-clock basis.
The primary objective for the exploration drilling of oil and gas wells is to find and develop new energy sources that can meet the energy demands of the future. It is also universally accepted that this objective must be met safely and efficiently.
Real-time operations go a long way toward ensuring safety for the oilfield; the ability to remotely monitor operations avoids the need for experts or other non-essential people on location. This reduces the exposure risks associated with travel or rigsite presence for a number of people. The safety factor extends beyond the physical transportation or presence of individuals at a work location because, by monitoring subsurface pore pressure trends, shallow flow hazards can be detected early and a recourse taken. The well is essentially under the discernible watch of several experts at critical points ensuring the delivery of a safe and efficient well.
Several other operational benefits can be realized from real-time operations. This paper discusses several of the tangible gains realized from this type of operation and the future it holds for its users.
Expandable-Drilling-Liner Technology: First Commercial Deployment of a Monobore Liner Extension
Authors: Stockmeyer Carl F. , Adam Mark K. , Emerson Alan B. , Baker Robert V. , Coolidge Robert B. 
Published: December 2007

Abstract
For a number of years the E&P industry has sought to prove the feasibility of monobore expandable liner extensions as an advantageous alternative to the "telescoping" nature of conventional casing designs (Figure 1). Collaboration between an operator and a supplier has produced a system that accomplishes this purpose for a 9 5/8" or 9 7/8" parent casing string to maintain 8 ½" drift post-expansion. Utilization of this well construction product can be planned as either a basis of casing design, or as a planned contingency.
Figure #1 Casing Designs
The objective and value of the monobore extension enables the operator to implement one more casing string, without reducing hole size. As a basis of design, this technology provides the option for the operator to begin well construction with one smaller casing size, which may drive down costs significantly, especially in high cost drilling and "floater" drilling programs. As a contingency, the product can isolate trouble zones such as reactive shales, sub-salt rubble zones, and low fracture gradient transitions without being forced to reduce casing size and subsequent drilled hole size. This capability can yield immeasurable benefits when retaining hole size means being able to either evaluate the reservoir as fully as desired, or to produce wells at rates deemed commercially necessary and optimum.
The technology development collaboration produced a one-trip, top-down expansion system that was developed, tested and proved the technical feasibility of the expandable monobore liner extension concept.
This paper details:
➢ Key System Features and Benefits ➢ System Development Downhole recess shoe qualification Casing selection qualification Zonal Isolation Requirements Monobore liner extension selection, one trip system ➢ Field Trial Pre-planning Expansion Process Post deployment results ➢ Planned Contingency Applications ➢ Casing BOD (Basis of Design) Applications ➢ Summary