bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reversible Invert Emulsion System used to Significantly Increase Water Injection Rates in an Open Hole, Stand-Alone Screen Completion in West Africa
Authors: Dick M. A. , Svoboda C. , Jones M. 
Published: December 2007

Abstract
Increasing water injection rate at low injection pressures with low cost has always been a goal of any reservoir pressure maintenance program. During the development of an offshore West Africa field, the operator has discovered a method to significantly increase water injection rate at low injection pressures.
This paper describes the utilization of a number of new technologies to drill and complete a 2,109-foot section. The well was drilled in a geologically challenging reservoir containing inter-bedded shales. The project was planned with geological, drilling/completion and injectivity goals in mind. The high-rate water injector was completed open hole with a stand-alone screen. A number of new technologies were used during the drilling and completion phase of this well includes: Specially designed reversible invert emulsion reservoir drill-in fluidUtilization of a completion screen flow through testUnique displacement sequenceSpecially designed organic acid cleanup treatment
Compared to best offset drilled with a low-solids, conventional oil-based mud this operation resulted in a 280 % increase in the water injection rate with a 50% decrease in injection pressure.
Assessing Profitability of Well Interventions on Mature Fields: Well Intervention Profitability Evaluation Method, case study from Cameroon
Authors: Buffet Michael , Mastin Eric , Maguerez Michel , Amiell Patrick 
Published: December 2007

Abstract
The Well Intervention Profitability Evaluation Project was aimed at applying a BP Corporate methodology (WETS, Wellwork Evaluation Tracking System, SPE 30649) to TotalFinaElf's Mature Fields.
When Oil Fields become "mature", drilling new wells may not necessarily be the appropriate solution to grab additional barrels and counterbalance the natural production decline. Progressively, TotalFinaElf Subsidiaries implement well intervention programs designed to recover or boost productivity. A wide range of such interventions is investigated and usually end up performing "spot" operations (a fracturation job, an acid job, a water shut-off …).
Often, when spot interventions prove successful, the idea comes to generalize these proven solutions and perform such interventions more systematically (campaigns). In terms of investments, although costs usually stay much lower than drilling costs, the financial impact may still be significant in subsidiaries where profitability can be "borderline".
Therefore, assessing the real financial impact / profitability of these campaigns needs more than "basic" return on investment calculations.
In one sentence, the method is aimed at Assessing the Profitability (over the time) of a given Wellwork Intervention (fracturations, acidifications, workovers, etc…). By plotting "Cost versus Net Present Value (NPV)", one can draw "scorpion" plots gathering, in an ordered way (decreasing NPV/Investment), all interventions perfomed on corresponding wells. A comparison "Campain X versus Campain Y, Z,…" can also be performed.
Then, the method, applied to an intervention campaign, is a 4 step process: –Evaluate the oil gain over a significant period of time as precisely as possible using an oil field management production data base. An adjusted cost per well is also computed at this stage,–Build and run a "light" economical model, taking into account the production contract and fiscal particularities, and this for each well,–Draw the "scorpion" plots (different durations can be considered) and highlight significant wells plus particular cases on each campaign. Draw conclusions,–Plot different campaigns (if applicable) on the same chart (cumulative NPV versus cumulative cost). Draw conclusions on relative profitability.
This paper comes back first on the methodology followed, then presents the case study of Cameroon which helped calibrating and assessing the interest of the method. Conclusions on the profitability of stimulations campaigns in Cameroon were straightforward and improvement tracks could also be highlighted thanks to this method.
Relative Permeabilities in Co-Current Three-Phase Displacements With Gravity
Authors: Juanes Ruben , Patzek Tad W. 
Published: December 2007

Abstract
We study the character of the equations in the traditional formulation of one-dimensional immiscible three-phase flow with gravity, in the limit of negligible capillarity. We extend our previous analysis, presented in SPE 77539, to incorporate the effects of gravity. We restrict our analysis to co-current flow required for a displacement process; in cases of mixed co-current and counter-current flow, capillarity effects cannot be dropped from the formulation. The model makes use of the classical multiphase extension of Darcy’s equation. It is well known that, if relative permeabilities are taken as fixed functions of saturations, the model yields regions in the saturation space where the system of equations is locally elliptic. We regard elliptic behavior as a nonphysical artifact of an incomplete formulation. We derive conditions on the relative permeabilities so that the system of governing equations is strictly hyperbolic. The key point is to acknowledge that a Darcy-type formulation is insufficient to capture all the physics of three-phase flow and that, consequently, the relative permeabilities are junctionals that depend on the fluid viscosity ratio and the gravity number. The derived conditions are consistent with the type of displacements that take place in porous media. By means of an illustrative example, we show how elliptic behavior can be removed, even when using simplistic relative permeability models.
Identification of Contaminanted Data in Hydraulic Fracturing Databases: Application to the Codell Formation in the DJ Basin
Authors: Popa Andrei S. , Mohaghegh Shahab D. , Gaskari Razi , Ameri Samuel 
Published: December 2007

Abstract
With the advance of computer technologies, digitized data is becoming increasingly available. Currently, many companies are in possession of oil or gas-field databases that contain large amounts of information related to hydraulic fracturing, reservoir characterization, production, drilling, etc. However, not all the records are completely accurate or reflect reality. Errors in stored data can be subjective or objective and can be the result of improper or incomplete data collection, errors in data entry, lack of proper interpretation and others. These errors can later lead to poor, erroneous, or even impossible interpretation of the data. This leads to the question: how much of the data is reliable and how can the contaminated data be identified?
The paper presents a new methodology for identification of contaminated data in hydraulic fracturing databases. The methodology combines a set of artificial intelligence tools, which integrates clustering techniques, neural networks modeling and an iterative process to achieve its convergence goal. The result can be seen as a separation of data into three categories: good data, slightly contaminated data, and "bad" data.
This new methodology is applied to two database cases. In the first case, random records in a sample database were intentionally corrupted. Then, using the new methodology presented in this paper, these records were identified as being contaminated. The second case involves a real situation in a Patina Oil and Gas Corporation hydraulic fracturing database, where using classic approaches, the data was unusable for any artificial intelligence processes. After applying this methodology to identify contaminated data, successful fracturing interpretation was performed.
A Novel Expert System for Multilateral Well Completion
Authors: Garrouch Ali A. , Lababidi Haitham M. S. , Ebrahim Abdullah 
Published: December 2007

Abstract
In this study, we assembled and put under scruitiny variables that affect the drilling and completion of multilateral and horizontal wells. We then formulated reservoir candidate screening criteria for applying multilateral technology, and implemented these criteria in an expert system for designing optimal multilateral well configuration and completion using the leading edge technologies of simple and complex multilateral junctions. The system features the use of fuzzy logic for handling ambiguous completion scenarios.
The main benefits of horizontal wells consist of lowering the development and lifting costs per barrel of oil produced. Multilateral technology multiplies these benefits by adding more reservoir exposure per well, and more exposure per drilling and completion dollar spent. The recent evolution of multilateral technology introduced a large variation of completion options for multilateral wells. Many of these options are simple and basic while others are complex. The development of this fuzzy expert system allows the use of multilaterals in a much wider range of well scenarios, and allows to account for a large number of production-styles constraints and rock-properties conditions.
Integrated Interpretation of Pressure Transient and Injection Profile for an Undulating Dual-Lateral Well
Authors: Ouyang Liang-Biao , Kikani Jitendra 
Published: December 2007

Abstract
Integrated evaluation of bottomhole pressure (BHP) and Water Flow Log (WFL) data from an undulating dual-lateral well provided significant insights into the contribution, flow performance and injectivity of the well. This allowed the setting of long-term performance characteristics for the well design in a multi-layered reservoir.
The injectivity test data (BHP pressure and injection profile) acquired in the first lateral and the DST data acquired in the second lateral were analyzed using a multi-lateral well modeling package designed for a multi-layered reservoir.
Useful and consistent interpretation not only increased confidence but has assisted in making sound reservoir management decisions. Major observations include: The average vertical to horizontal permeability ratio, (kv/kh), a difficult parameter to compute, in general, was determined with an excellent match spanning ten injection and two falloff periods in one lateral and four drawdowns and two buildups in the other.Injection profiles at two different water injection rates were predicted and compared with results based on RST/WFL log. Excellent agreement was achieved. It is demonstrated that the agreement could be further improved if a non-constant correction factor was used in interpreting RST/WFL log data.Well productivity and injectivity indices are dependent upon production/injection time and history. For both the well laterals, the late-time productivity/injectivity index equals to around 11 STB/d/psi.
Successful Horizontal Producers in Midway-Sunset Thermal Operations
Authors: McKay Charles , Jones Jeff , Pomerene Joel 
Published: December 2007

Abstract
Berry Petroleum Company (Berry) has been involved in thermal recovery operations in the Midway-Sunset Field since the inception of the process. The majority of Berry's properties are under cyclic stimulation and several are quite mature. Cyclic steaming combined with high (60°) structural dip present in the Monarch Formation has proven to be a very efficient recovery mechanism to date. Over the past five years Berry Petroleum Company has successfully applied horizontal drilling technology to significantly improve production efficiency in its South Midway-Sunset operation.
Since 1996 over 50 medium-radius horizontal producing wells have been drilled in the Monarch Formation in South Midway. By being drilled generally in the dip direction with a basal lateral placement, these horizontal wellbores expose all of the Monarch sand section to production and provide a means to produce the lowermost oil-bearing strata economically. Vertical well development alone would leave wedges of reservoir unprocessed due to the steep dip of the formation.
This paper will discuss the design, drilling and operational considerations as well as the performance of these horizontal producers. Comparisons of the performance of wells located in areas of differing thermal maturity will be made as well as comparisons to typical vertical wells in each area.
Cement Evaluation Under Extreme Conditions
Authors: Morris Charles , Garcia Chris , Wydrinski Ray , Tinker Steven J. , Mullen Mike , Collins Andrew 
Published: December 2007

Abstract
The completions of ultra-deepwater wells in the Gulf of Mexico are requiring higher mud weights and heavier casing strings in order to economically maximize production rates and to control high-pressure reservoirs. Many operators are completing multiple wells using synthetic oil-based mud weights in excess of 15 lbm/gal, casing with a wall thickness of more than 0.625 in. and special cement materials. Standard cement bond logging tools, however, may not be well suited to evaluate the extreme casing conditions or analyze the casing/cement interface because of the acoustic properties of these materials.
In order to obtain quality answers to the casing/cement evaluation questions, a study was performed to evaluate the results provided by sonic and ultrasonic tools in the different casing materials. The results were obtained from a combination of special small-scale experiments and field applications. This work provides the technical background for extending the ultrasonic measurements beyond normal industry conditions. The measurement resolution and limitations in these extreme conditions are also discussed. It was found that the latest generation of ultrasonic cement evaluation tools could provide high-quality measurements of the casing dimensions and the cement acoustic impedance properties when utilizing the proposed procedures. Field examples are presented to illustrate the actual application and the response of the ultrasonic tools to various extreme cement evaluation conditions.
Decommissioning of Belmont Island, an Offshore Oil Platform
Authors: Ahuja Madhu P. , McGufee J. Cris , Poulter Simon A. 
Published: December 2007

Abstract
Belmont Island was a man-made oil drilling and production island located approximately 8,100 feet offshore of the City of Seal Beach, California in about 42 feet of water. The island was located on State Oil and Gas Lease PRC 186, which contained approximately 1,225 acres of tide and submerged lands located within the Belmont Offshore Field in Orange County, California. During the 40-year active life of the Island, the wells produced approximately 28 million barrels of oil and 24 million cubic feet of natural gas. The State received over $40 million revenue and the operations grossed over $240 million. ExxonMobil terminated oil and gas production in 1994 due to declining production rates.
This fixture in the waters off Seal Beach, survived nearly fifty years as the State’s first offshore oil production facility, Belmont Island became the first man-made oil production island removed from the ocean waters off the California shoreline. After a nearly five year permitting process, the physical removal required 21 months, and was completed in January 2002 with no reportable accidents and no environmental incidents. All of the Island’s components were completely removed except for components buried below the natural seafloor.
The Belmont Island project provides a snapshot of the key issues and technical challenges facing decommissioning projects in today’s regulatory climate. Such challenges included the handling of hydrocarbon contaminated materials in the caisson core, cutting and removal of lead painted concrete and steel surfaces, and the logistical challenges of handling island materials on a gradually smaller work surface. This paper will provide an overview of these challenges and the approaches developed by the project team to address these challenges.
Light-Oil Steamdrive in Fractured Low-Permeability Reservoirs
Authors: Hoffman B. Todd , Kovscek Anthony R. 
Published: December 2007

Abstract
Steam injection into heavy oils has been well characterized over the last 40 years, and while steam has been injected into light oils almost as long, the mechanisms and effectiveness of this process are much less understood. When this lack of understanding is coupled with the complexities of flow in low permeability fractured reservoirs, even less is known. This study examines thermal recovery in low permeability, fractured reservoirs using thermal compositional simulation. A diatomaceous reservoir provided input for the rock model. The oil phase is represented by three pseudo-components that characterize a relatively light crude oil. Both the areal and vertical recovery efficiencies are improved for steam injection compared to water injection. The incremental recovery depends on the distribution of permeability and is greatest for homogeneous distributions.
In regard to recovery mechanisms, thermal expansion of the hydrocarbon fluids accounts for over half of the incremental recovery early in the steam drive; after roughly 0.4 pore volume of steam injection (cold water basis), the incremental recovery is split equally among thermal expansion, vaporization, and oil viscosity reduction. Late time behavior is dominated by vaporization as the distillate bank breaks through to the producer. As a consequence of steam injection three separate fluid banks form: a cold water bank, a combined hot water and distillate bank, and the steam front. Hence, displacement mechanisms are substantially different from the heavy-oil situation where oil viscosity reduction and, frequently, gravity drainage are dominant. Although the study uses a diatomite rock and fluid model, this work clearly extends to include all low permeability fractured reservoirs that have low primary and waterflood recoveries. For such reservoirs, significant additional recovery is obtained by implementing a steam drive.
Fault Identification and Modeling for Production Enhancement
Authors: Yang An-Ping , Eacmen J. C. 
Published: December 2007

Abstract
The Kern River Field has been under steam flood thermal recovery for many years. Faults with even small throw can significantly affect the flow of steam and flow of heated oil. By identifying the spatial distribution of faults, steam injection, perforation, an infill well can be better planned to recover more oil at lower cost.
Seismic data are unavailable for the Kern River Field. Fault identification is based on well data. There are three main approaches in fault identification with well data: Areal analysis of sand and horizon correlation or production anomaly. This helps identify areas where there may be faults.Well pair sand correlation dip variation along depth. A change in apparent dip may indicate fault intercepting with a well.Well pair visual correlation. This is a common method used for well correlation and fault identification
A systematic procedure has been developed to integrate the three approaches. Fault interceptions at different wells are modeled into fault surfaces with consistency checking of fault dip and throw variation along the fault. Fault throws as small as 5 to 10 ft can be identified and modeled.
With a three-dimensional model of the faults, three-dimensional distribution of sand, temperature, and remaining oil saturation can be modeled to the correct positions.
Role of Small-scale Variations in Water Saturation in Optimization of Steam Flood Heavy Oil Recovery in the Midway-Sunset Field, California
Authors: Schamel Steven , Deo Milind 
Published: December 2007

Abstract
In recovery of heavy oil by steam flood’ efficiencies can be realized by limiting the placement of steam to portions of the reservoir with highest oil saturations, thus reducing the disproportionate loss of heat to connate water. This optimization strategy requires knowledge of water saturation (Sw) distributions within the heavy oil reservoir at the scale of operations. Application of this strategy has contributed to the successful reactivation of the shut-in Pru Fee property in the Midway-Sunset field one mile west of Taft, a DOE Class 3 oil technology demonstration project.
The 40 new wells drilled and logged within the 40 acre Pre Fee property together with a single continuous core have permitted 3D mapping of Sw within the 250–350 ft thick pay zone in the Monarch Sand reservoir. Water saturations are observed to vary at three different scales: A systematic vertical reduction in Sw through a 100–150 ft interval above the OWC due to dominate capillary influence where the buoyancy effects are diminished by the low density contrast of the 13º API oil and formation water.Lateral variations in Sw on the scale of 10–100 ft due principally to prior oil production from the reservoir, but modified by its internal stratigraphic architecture.Bed-to-bed variations in Sw on the order of a few feet or less constrained by grain-size controlled differences in porosity-permeability in these crudely graded sands.
Overall production efficiency in steam flood has been improved by limiting steam injection to the upper one-half to two-thirds of the pay zone, where Sw is lowest. Knowledge of the lateral variations in Sw has permitted more accurate appraisal of the effectiveness of individual producers and nine-spot injector-producer arrays. The recognition of the bed-to-bed variations has permitted a better petrophysical model for calibrating Sw calculated from logs.
Rose Field: Surface Tilt Mapping Shows Complex Fracture Growth in 2500’ Laterals Completed with Uncemented Liners
Authors: Minner W. A. , Du J. , Ganong B. L. , Lackey C. B. , Demetrius S. L. , Wright C. A. 
Published: December 2007

Abstract
The Rose field in central California produces oil from the McLure shale, a low permeability overpressured quartz-phase siliceous shale interval at 8000’ depth. The field has been developed with horizontal wells, completed with an uncemented liner and a single hydraulic fracture treatment to cover the average 2500’ lateral length. Based on initial vertical well experience in the adjoining North Shafter field, this horizontal well strategy greatly improves the ability to place hydraulic fracture treatments, and improves well economics by accessing a greater volume of reservoir rock per well. However, the half-mile long completion interval and the uncemented liner unavoidably add uncertainty to fracture treatment distribution along the lateral. Using limited entry perforation strategy, does the completion technique effectively stimulate the entire target lateral interval? To assist with answering this question, the fracture diagnostic of surface tiltmeter fracture mapping was used to evaluate fracture growth during the nine fracture treatments. Tilt results include fracture orientation and the approximate location and volume distribution of fracture components along the lateral.
The original intention of the uncemented liner strategy in the McLure shale was to align the wellbore with the preferred fracture orientation, thus resulting in the initiation and propagation of a simple longitudinal fracture along the entire lateral. However, the actual fracture growth pattern was found to be much more complex, with vertical fracture components in two orthogonal directions, and a significant horizontal fracture component. Considering overall averages, about 45% of fracture volume was contained in transverse fracture components (~N60°W), while 35% of fracture volume was in longitudinal components (~N30°E), and the remainder in horizontal fractures. This complex multiple-component fracture growth is believed to be due to a small in-situ stress bias, combined with the impact of the completion technique and the naturally fractured character of the McLure shale.
Fracture orientation and approximate component distribution along the lateral are compared and discussed for the nine treatments evaluated. Although the uncemented liner technique did not achieve the original intent of longitudinal fracture dominance, reasonable lateral coverage was achieved. Based on 1-year cumulative production, the limited dataset is suggestive, but not conclusive, that horizontal and transverse fracture growth is preferable to longitudinal fracture growth.