bluuebunny/crossref_metadata_2025_split huggingface dataset:
Waterflooding Surveillance and Monitoring: Putting Principles Into Practice
Authors: Terrado M. , Yudono S. , Thakur G. 
Published: December 2007

Abstract
This paper illustrates how practical application of surveillance and monitoring principles are keys to understanding reservoir performance and identifying opportunities that will improve ultimate oil recovery. Implementation of various principles recommended by industry experts is presented using examples from fields currently in production.
Practices on how to process valuable information and analyze data from different perspectives are presented in a methodical way on the following bases: field, block, pattern, and wells. A novel diagnostic plot is presented to assess well performance and identify problem wells for the field.
Results from the application of these practices in a pilot area are shared, indicating that the nominal decline rate improved from 33% to 18% per year without any infill drilling. The change in the decline rate is primarily attributed to effective waterflood management with a methodical approach, employing an integrated multi-functional team.
Although the suggested techniques can be applied to any oil field undergoing a waterflood, they are of great value to mature waterfloods that involve significant production history. In these cases, prioritization is a key aspect to maintain focus on the opportunities that will add most value during the final period of the depletion cycle. Case studies illustrating the best surveillance practices are discussed.
Utilizing Computational Fluid Dynamics (CFD) Analysis as a Design Tool in Frac-Packing Applications To Improve Erosion Life
Authors: Clem N. J. , Coronado M. P. , Mody R. K. 
Published: December 2007

Abstract
Frac packing tool erosion is becoming a growing concern as more high-profile deepwater wells are completed using this technique. Today many deepwater wells require frac pack pump rates of at least 40 barrels per minute (bbl/min) with proppant loads reaching 300,000 lbs. As zone lengths are increased and multi-zone operations are performed jobs requiring 60 bbl/min pump rates with proppant loads reaching 900,000 lbs. may be more typical. The current frac packing tool designs must be optimized to accommodate the higher pump rates and proppant volumes required to complete these deepwater wells.
Computational fluid dynamics (CFD) analysis of these systems provides valuable insight to what is physically happening to the tools at these high pump rates and proppant loads. Analyzing various patterns, such as velocity, fluid path, erosion, and sand concentration at high rates helps identify critical areas within the system that require design optimization. CFD analysis is a cost effective alternative to trial-and-error testing, which can cost upwards of $150,000 per test and prolong the development phase.
Two sizes of systems have been analyzed using CFD analysis and modified based on the results of that analysis. Full scale tests were also performed at 40 bbl/min on these two systems to compare the actual results with that of the CFD analysis. The CFD analysis was able to generate accurate profiles of the physical erosion patterns observed after the full scale tests were completed. Although CFD cannot accurately predict magnitudes for erosion rates, it can predict erosion profiles and velocity magnitudes. Research is currently ongoing to accurately predict erosion rate magnitudes.
This paper will detail the development, analysis and qualification testing of a next-generation frac packing system capable of use in ultra-high-rate operations.
Integrated Project Management in South Mexico and Well Construction Optimization on Deep and Depleted Carbonates
Authors: Jenrette M. , Murillo J. , Mandujano H. 
Published: December 2007

Abstract
The Bermudez Complex is located in South Mexico; it constitutes of three main fields: Iride, Samaria and Cunduacan and was discovered in 1972. In terms of oil production it is the most important field in the southern region and is one of the principle blocks in the country. Production exceeded half a million of barrels per day in the past; however since then it has experienced a drastic formation pressure reduction.
Well construction in the area has been characterized by the difficulties experienced in effectively isolating the high pressure zones located just above the carbonates in the reservoir, and by the need to drill the pay zone with hydrostatic equivalents much lower than the ones generated by conventional liquid fluids. The depth of the wells, the structure tectonically disturbed by fractured and faulted blocks, the high temperature and the need for directional drilling control, are variables that challenge the design and drilling of these wells.
Recently, a typical integrated drilling and completion commercial scheme has been implemented in the complex using five large drilling rigs operating simultaneously and managed by an integrated Project Management team allowing flexibility in applying new technologies along with standard products and services.
In spite of the unfavorable and extremely low reservoir pressures, the drilling and completion times have been considerably optimized through the application of several techniques and processes that when properly applied and coordinated allowed the project to reach aggressive goals. The main practices and technologies applied are as follows: drilling with foam densities as low as 2.9 ppg, isolation of different productive zones under hostile environments, use of the latest generation of drilling bits, a process for defining the technical limits and the capturing of best practices/lessons learned, and finally a multidisciplinary task team working closely with geosciences support enabling optimal casing seat on a highly complex geological environment.
Case History—Application of a New PDC Bit Design in Deep Cretaceous and Jurassic Hard Formations in Southern Mexico
Authors: Bejarano C. A. , Muñoz G. , Perez G. , Cortina C. , Palomo R. 
Published: December 2007

Abstract
In the Tecominoacan Field in Southeastern Mexico, discovered in October 1980, approximately 107 wells have been drilled to date. One of the biggest challenges of these wells is drilling the production interval, which is comprised of fractured limestones and dolomites interbedded with cherty stringers.
Historically, of the different bit types and designs tested in the field, the most successful were insert tricone rock bits (IADC 517-537). Even then, multiple trips and low rates of penetration were common while drilling the 8 ½" and 5 7/8" hole sections. Because of natural depletion of the productive formations, penetrating these target intervals requires underbalance drilling techniques that negatively impact bit performance: less bit life due to seal failure, increased trips and decreased bit reliability.
An exhaustive analysis of bit performance in the field, including bit wear comparison, and introduction of new materials led to bit design adjustments based on hard rock drilling concepts. The resulting fixed cutter design, with high density cutters incorporating the latest-generation PDC cutter materials, achieved dramatic performance improvements.
Where typical rock bit performance in Tecominoacan Field wells averaged penetration rates of 4m/hr in 8 ½" and 5 7/8" hole sections, the new PDC bit design doubled that performance, delivering immediate benefits in saved time, fewer trips, longer bit life and less bit wear.
The paper presents case history performance that demonstrates how this hard rock bit technology could be of benefit in other areas with similar lithology and hole conditions.
Material Balance and Boundary-Dominated Flow Models for Hydrate-Capped Gas Reservoirs
Authors: Gerami S. , Pooladi-Darvish M. 
Published: December 2007

Abstract
Gas hydrates are being considered as an alternative energy resource of the future, considering the enormous quantities existing in permafrost and offshore environments. Some of the hydrate reservoirs discovered (e.g., in Alaska and Siberia) are overlying a free-gas layer. These reservoirs are thought to be the easiest and probably the first type of hydrate reservoirs to be produced1.
This paper presents the first-ever developed material balance model for such a reservoir (which we shall call a hydrate-capped gas reservoir). The technique presented herein differs from the traditional approach of applying material balance methods to conventional gas reservoirs because it includes the effects of gas generated from hydrate decomposition and its associated cooling effect. The material balance equation is developed by analytically and simultaneously solving the mass and energy balance equations. The solution yields the average reservoir pressure and the gas generated from hydrate decomposition as a function of cumulative gas produced, for a reservoir that is produced at a constant rate. In the second portion of the paper, we develop a flowing material balance equation by first writing the inflow performance equation, relating the wellbore pressure to the average reservoir pressure and then combining it with the material balance equation. This yields an estimate of initial gas-in-place from production data.
Using a recently developed hydrate reservoir simulator, it is shown that this model is valid over a wide range of reservoir parameters. The success of this model relies on coupling of the energy and mass balance equations, where the energy equation accounts for the endothermic nature of hydrate decomposition.
In its "forward solution" mode, the model developed here is used as an engineering tool for evaluating the role of hydrates in improving the productivity and extending life of hydrate-capped gas reservoirs. In addition, in its "backward solution" or inverse approach mode, the application of this new model is providing an estimate of initial free gas-in-place from production data.
Integration of Borehole Imaging, Openhole Logs, Nuclear-Magnetic-Resonance/Modular Dynamic Tester, and Advanced Production Logging as a Guide for Perforation Intervals Selection in Thin-Bedded Sands and Shales
Authors: Daoud A. M. , Eisa M. , El-Mahdy R. , Emam M. , Hashem A. H. , Elhawary A. S. 
Published: December 2007

Abstract
Specifying the perforation intervals and evaluating the productivity of thin-bedded sands and shales is crucial for well completion cost optimization. This requires the accurate identification of hydrocarbon-bearing sands and their contribution to production. Relying only on borehole-imaging tools to select the productive intervals is not suitable in this lithologic type because of the difficulty of permeability quantification.
In this paper we present a technique to integrate the detection of hydrocarbon-bearing sands with water saturation information and an estimation of permeability. Hydrocarbon-bearing sands are detected by high-resolution resistivity from borehole-imaging tools combined with water saturation from openhole logs (OHL), and permeability from nuclear magnetic resonance (NMR) or a modular dynamic tester tool.
We use the geostatistical concept of indicators to convert the inputs from these tools into binary data (0 and 1) based on the best selected cutoffs for those inputs, where a value of 1 means that location is good to perforate. The results of this integration are compared to the results from the production logging tool that is sensitive to the laminated sand units for evaluating its actual productivity. The best cutoffs to select for those parameters are in good agreement with the production logging tool results. The result is a set of optimized perforation intervals consistent with all the data. In addition to the certainty percent associated with the selection of perforation intervals.
Three gas wells producing from the same formation were used to apply this technique. One of the three wells was used to select the best cutoffs. For the other two wells, we used the same cutoffs to select the best perforation intervals and determine the certainty associated with them. The correct selection of the perforation intervals from the two wells was confirmed with the production testing and production logging results.
Transversly Multi-Fractured Horizontal Wells: A Recipe for Success
Authors: Demarchos A. S. , Porcu M. M. , Economides M. J. 
Published: December 2007

Abstract
While the hydraulic fracturing of vertical wells is perhaps the most widely used method for production/injection enhancement in the petroleum industry, the fracturing of horizontal wells has been used sparsely, mostly in the United States and the North Sea. Usually this involves either longitudinal fractures or treatments with no regard to the well orientation and fracture azimuth.
The systematic transverse fracturing of horizontal wells poses several challenges in design and optimization and in operations and execution. A multi-fracture design and a feasibility study are performed to identify candidates for both a technical and an economic success. We used a fractured vertical well as the basis of our calculations and we have determined the dimensionless PI as the means to evaluate the attractiveness of multiple transverse fractures intersecting a horizontal well.
In previous publications we have presented the Unified Fracture Design and how its adaptation by several companies and researchers led to major new successes. The drainage shape and flow regime in transversely fractured wells differs significantly from vertical wells. The Unified Fracture Design had to be adapted with shape factors to account for the differences. We are showing a series of designs using a range of sizes of fracture volumes, different proppant types and drainage sizes.
For treatment execution, traditional methods of perforating may increase the probability of failure. The types of reservoir which are candidates for these treatments such as multi-layered reservoirs will almost surely affect the fracture initiation, and, as usual, composite materials show higher mechanical resistances compared to homogeneous materials. A new abrasive jet cutting tool has now been designed and built specifically for this type of jobs.
In this paper we will present all the design and operational challenges that will be faced in such fracturing project, and make recommendations for successful treatments
Analytical and Numerical Solution of Nonisothermal Buckley-Leverett Flow Including Tracers
Authors: Sumnu-Dindoruk D. , Dindoruk B. 
Published: December 2007

Abstract
Mass balances for two immiscible fluids and tracer and convective heat balance form a system of three equations (non-isothermal Buckley-Leverett Problem - ref. 1 -with Tracers). Tracer component is considered to investigate the propagation of a tracer in order to track the flood (or to track a miscible inert contaminant introduced during drilling). We have solved the resulting non-isothermal two-phase convective flow equation in porous media analytically, including a tracer component (i.e., cold or hot waterflooding with and without tracer). Method Of Characteristics (MOC) is used as a solution technique after transforming the balance equations in a form that can easily be solved with two Welge tangents (refs. 2-7). Our solution technique is valid for both radial and linear flow models.
In practice, these solutions can be used:To investigate the convective flow behavior around the wells (i.e., sudden fluid losses, convective near-well tracer propagation, analyzing pressure transients).To interpret formation testing tool responses by detecting the location of the thermal front or to estimate the temperature buildup time that is needed for Horner type of analysis (for the identification of the formation temperature).To calculate the location of the cold or hot water front (thermal water) while injecting cold or hot water. This will yield the limit of the maximum temperature disturbance around the well.To test/scale relative thermal effects of various systems against each other.To test the accuracy of simulators and provide benchmark solutions.To interpret relevant laboratory experiments quickly.
Such solutions helped us to understand the depth of influence of the temperature variations and its influence on the transport properties, in both radial and linear systems. Solutions analytically proved that the thermal front propagates much slower than the flood front. This explains why isothermal black oil simulators still work although the injected water temperature is not always equal to the reservoir temperature.
Furthermore, we have checked/verified our results against a commercial thermal simulator (ref. 8) and investigated the impact of numerical diffusion on the thermal front as well as conductivity. This part of the work revealed that the temperature front is more prone to numerical diffusion.
Generation of Curves of Effective Gas Separation at the ESP Intake on the Basis of Processed Real Measurements Collected in the Priobskoye Oil Field
Authors: Gadbrashitov I. F. , Sudeyev I. V. 
Published: December 2007

Abstract
Well performance monitoring is extremely useful to effectively control hydrocarbon production and make timely decisions when it comes to run various well interventions. The more ample and correct are the data at our disposal, the more efficient will be the management. Traditionally little attention is given to the gas liberated at oil degassing and no measurements are taken; although this kind of data would allow computing a number of rather critical figures, such as gas content in the mixture, bottomhole pressure, etc.
For the moment maximum 20% of all the wells in the Priobskoye field are outfitted with the PHD sensors, and the BHP as well as the pressure at the ESP intake for the most of the wells are computed. This kind of computation requires an ESP separation efficiency function. However, all the available efficiency-function computation equations are based on tests run on recombined liquid/gas mixtures at lab setups, that is, under ideal conditions.
In this paper we put focus on the efforts to evaluate the free gas separation at the ESP intake; estimate the bottomhole pressure based on production data; and assess the gas separation impact on both the pumping unit performance (variation of Q-H characteristics) and the in the tubing and annulus flow parameters.
Measurements of the dynamic level and wellhead annulus pressure that vary with time and allow computation of the fraction of the gas separated were used as input data. As well as the data collected with the PHD sensors, or pressure gauges below the ESP.
Semiautomatic Multiple Resolution Design for History Matching
Authors: Li B. , Friedmann F. 
Published: December 2007

Abstract
History matching is an inverse problem, in which an engineer calibrates key geological/fluid flow parameters via fitting simulator's output to the real reservoir production history. It has no unique solution, because of insufficient constraints. History match solutions are obtained by searching for minima of an objective function below a pre-selected threshold value. Experimental design and response surface methodologies provide an efficient approach to build objective functions (OF) for history matching. The search for minima can then be easily performed on the reconstructed OF as long as its accuracy is acceptable.
In this paper, we first introduce a novel experimental design methodology for semi-automatically selecting the sampling points, which are used to improve the accuracy of reconstructed non-linear OF. This method is based on derivatives of reconstructed response surfaces.
We propose an iterative procedure for history matching, applying this new design methodology. To obtain the global optima, the objective functions are initially constructed on the global parameter space. The objective function is iteratively improved until adequate accuracy is achieved. We locate sub-spaces in the vicinity of the optima regions using a clustering technique to improve the accuracy of the reconstructed OF in these sub-spaces.
We test this novel methodology and history matching procedure with two waterflooded reservoir models. One model is the Imperial College fault model1. It contains a large bank of simulation runs. The other is a modified version of SPE92 benchmark problem. We demonstrate the efficiency of this newly developed history matching technique.
CO2 Sequestration in Depleted Gas/Condensate Reservoirs
Authors: Shtepani E. 
Published: December 2007

Abstract
Depleted gas condensate reservoirs are becoming important targets for CO2 sequestration.
Since depleted below the dew point, retrograde condensate has been deposited in the pore system. CO2 injection in the depleted gas condensate reservoirs may allow enhanced gas recovery by liquid re-vaporization and reservoir re-pressurization or pressure maintenance.
The higher density of CO2 relative to gas condensate means that CO2 will tend to migrate downward. The larger viscosity of CO2 ensures that displacement of hydrocarbon gas phase by CO2 will be a displacement with a favorable mobility ratio. Furthermore, pressure diffusivity is typically several orders of magnitude larger than molecular diffusivity, making mixing by re-pressurization occur much faster than by molecular diffusion.
This paper discusses an approach that relates primarily to the laboratory and modeling studies that precede compositional simulations and field pilot testing of CO2 sequestration in depleted gas condensate reservoirs.
The phase behavior of CO2/gas condensate system as a critical factor in determining the effectiveness of a reservoir to store CO2 are reviewed along with its importance in building an accurate EOS model.
In addition to PVT experiments, a special core flood test design to determine the micro-scale conformance of the CO2 displacement, to identify CO2 breakthrough characteristics at density and compositional level during liquid re-vaporization and re-pressurization process and to evaluate the recovery performance is discussed in detail.
The results from experimental data can be used as a base for sensitivity case studies using a commercial compositional simulator to evaluate the feasibility of CO2 sequestration in depleted gas/ condensate reservoirs with enhanced gas recovery component.