bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geosteering Horizontal Wells in a Thin Oil Column
Authors: Barry Andrew , Burnett Phil , Meakin Chris 
Published: December 2007

Abstract
A multi-disciplinary team utilising state-of-the-art Logging While Drilling (LWD) technology is able to geologically "steer" horizontal wells in real-time within a thin oil column. Excellent well performances support the general validity of the geosteering approach and a static pressure survey in one of the wells verifies the steering accuracy.
The Tuna field M-l reservoir in the Glippsland Basin, Bass Strait, Australia contains a 12 m oil column overlain by a large gas cap and supported by a strong aquifer in multi-darcy sands. A total of 19 wells with horizontal sections of 300 to 1050 m in length are being drilled to develop the reserves, with all wells being steered using LWD data to maintain true vertical depth (TVD) control.
Reservoir simulation defines the optimal horizontal well placement as 4 m above the oil-water contact (OWC), within a TVD tolerance window of +1.5 m. Industry standard error models show that this tight geometric tolerance over the length of the wells is not possible using MWD survey data alone. Tying the MWD survey data to the known gas-oil contact (GOC) during the landing operation reduces the geometric error prior to drilling the horizontal section, while control of the geometric error during horizontal drilling is achieved using the real-time resistivity and neutron-density data.
Well log data show that the entire oil column is in transition, allowing an empirical algorithm to be developed relating the resistivity response to height above OWC for a range of rock qualities. For each well path, TVD is determined in real-time to verify the directional survey data and adjust the well trajectory when necessary.
Comprehensive pre-planning, discussion, documentation and management approval of the decision making process empowers the project team. The process steps of landing the horizontal section, well trajectory error limit management, early well total depth decision-making and external packer placement are discussed.
P. 221
Use of Pressure Monitoring to Improve Reservoir Management in an Offshore Recycled Gas Reservoir - Goodwyn Gas Condensate Field, NWS, Australia
Authors: Scott M. , Evans M. 
Published: December 2007

Abstract
Effective Reservoir Management of a large gas condensate recycling field requires early recognition of the degree of communication between injectors and producers, aquifer strength and management of the key reservoir uncertainties. The objective of this paper is to communicate the requirement, acquisition, justification, applications and value of pressure data to improve reservoir management of the Goodwyn field.
P. 251
Boolean Modelling of the Fluvial Mungaroo Formation, Gorgon Field, Northwest Shelf, Australia
Authors: Brenneman R.J. , Miller N.W.D. , Teakle R.P. , Seeburger D. , van Nispen D.J. , Harrison C.J. 
Published: December 2007

Abstract
The objective in building the Gorgon reservoir characterisation and simulation model was to create a 3D, object based model in a sequence stratigraphic framework integrating core, log, engineering, and seismic attribute data. The project team specified that software and work flow must incorporate marked point - boolean processes with or without seismic conditioning, recognise uncertainties in reservoir and model input parameters, generate multiple model realisations for a probabilistic range of gas in place, and output the model in reservoir simulation format. Reservoirs are in stacked sands of the Mungaroo Formation, with a total formation thickness of greater than 2000 m beneath the major Jurassic unconformity. The Mungaroo Formation was subdivided into 11 intervals on the basis of regional sequence boundaries and systems tracts. Relative lowstand intervals are sand prone, relative highstand intervals much less sand-prone. Facies present include fluvial channels (single channels and amalgamated stacked channels), crevasse splays, and "background" shale (coaly siltstone, coal, and minor carbonate). 3D seismic data were used both for structural modelling and a statistical correlation between seismic attributes and channel sand distribution. Wireline pressure data were used to refine our understanding of stratigraphic compartmentalisation and fluid distribution. The fluvial reservoir architecture model was built using marked point process and simulated annealing for each of the 11 stratigraphic intervals. A range of endpoint net/gross ratios was established based on well penetrations and seismic attributes. The model was scaled-up from a 715 layer geologic model to a 46 layer simulation model, with no areal scale-up. Whilst the scaled-up model honoured the 11 original intervals, the majority of the layers were located in regions identified as key flow units. The resulting simulation model was then used to generate production profiles for various development scenarios.
P. 305
Displacement of Oil by Water-Effect of Wettability, Rate, and Viscosity on Recovery
Authors: Moore T.F. , Slobod R.L. 
Published: December 2007

Abstract
The displacement of oil by water in typical porous media has been studied, using new equipment developed to handle flooding experiments on 1-in core plugs with a precision of about one pore per cent. Long core floods using cores up to 10 ft in length were used to supplement the short core studies. From the results of several thousand flooding experiments on a variety of porous media, we have found that the wettability is the single most important variable affecting the recovery history of a water flood. Cores are, therefore, usefully described as being (1) water-wet, (2) oil-wet, or of (3) intermediate wettability. This classification scheme has provided a sound basis for the interpretation of laboratory waterflooding data.
For water-wet cores it can be concluded:1-in core plugs show the same recovery history as long cores when flooded under the same conditions of rate, viscosity and wettability;recovery is practically independent of rate of flooding from reservoir rates up to 40 ft/day;at extremely high rates (over 100 ft/day) significant recovery increases were observed;displacement by imbibition alone displaces the same quantity of oil as water drives do with rates up to 40 ft/day;lowering the interfacial tension will reduce residual oil if the lowered value is maintained at the flood front.
An explanation for these conclusions based on the interplay of the viscous and capillary forces at the flood front (called "Viscap" concept) is presented, and from this we may conclude that laboratory floods of water-wet core plugs offer no particular scaling problems.
The intermediate wettability case is more complicated, and because of limitations in measuring the wettability of cores and the reservoir, this group needs more study.
The behavior of oil-wet cores is markedly different from the water-wet case. Generally, oil-wet cores show a considerable amount of oil production after water breakthrough even for a viscosity ratio of unity. Also, they exhibit a saturation gradient at the flood front (sometimes called an end effect). This end effect invalidates laboratory results unless the floods are scaled using a relationship involving length, viscosity, rate, interfacial tension and contact angle.

Introduction
The need for secondary recovery procedures to reduce the fraction of oil left in the reservoir is generally accepted by the oil industry. One of the most effective of these secondary recovery methods is water flooding.
Geological Considerations of the Weber Sand Reservoir, Rangely Field, Colorado
Authors: Larson Thomas C. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The heterogeneity of the Weber Sand Reservoir required that a geological evaluation be considered with reservoir engineering to enhance primary and secondary recovery. Stratigraphic: studies delineate a multilayered distribution of discrete sand bodies. Lenticularity, lithology, crossbeds, and fractures cause preferential drainage, prohibiting a favorable balance of production and injection wells in many sands. These geological parameters have been considered in analyzing parameters have been considered in analyzing reservoir performance with subsequent increased production. production.

GENERAL GEOLOGY AND RESERVOIR CHARACTERISTICS
Rangely Field is located in northwestern Colorado on the north plunge of the Douglas Creek Arch between the Piceance and Uinta Basins (Fig. 1). The principal production is from the Permo-Penn Weber formation. Accumulation is Permo-Penn Weber formation. Accumulation is localized on an anticline of Laramide age. The Weber formation interfingers across the structure into the arkosic Maroon formation to the south.
The stratigraphy and depositional history of the Weber is pertinent as it relates to the reservoir of the field. The section here consists of some 600 to 800 ft of interbedded sands, silts, and shales of the Weber formation with tongues of shale, silt, and arkose of the Maroon formation. In general, the Weber is a buff, clean, well-sorted, fine-grained sandstone with variable calcareous cementation. A littoral marine environment apparently predominated in this area during Weber time. This caused sand bodies of various depositional modes to form complex multilayered and laterally coalescing sand units. The texture indicates a reworked mature deposit. Separating or forming laterally equivalent facies to these sand units are gray and red shales, red silts, and coarse maroon arkoses generally considered deposited in a deltaic environment with a source attributed to the Uncompahgre Highlands to the south.
Depth to the top of the Weber in the field ranges from about 5,500 to 6,500 ft, and penetration varies from less than 100 to more than penetration varies from less than 100 to more than 700 ft, depending on structural position. Fig. 2 depicts the structure as mapped on top of the Weber formation. An initial gas cap of about 130 ft was present on the crest of the structure. An oil column of about 800 ft was encountered above the generally recognized oil-water contact of -1,150 ft.
Porosity, permeability, and saturations vary within the Weber and within the field. In general, porosity in the sand is estimated to average near 15 percent.
Analysis of Transient Pressure Response near a Horizontal Well – A Coupled Diffusion-deformation Approach
Authors: Li Y. , Wong R. C. K. , Yeung K. C. 
Published: December 2007

Abstract
Analysis of transient pressure response near a horizontal well has been based largely upon the analysis of mathematical solutions for the diffusivity equation. The diffusivity equation satisfies the principle of mass conservation, but does not consider the principle of equilibrium. No deformation properties of reservoir are included in the diffusivity equation. However, in some deformable reservoirs, the stress and deformation caused by injection or production could be so significant that it might affect the pressure response. This paper presents analyses of transient pressure response near a horizontal well using a coupled diffusion-deformation method. The results are compared with those obtained from the single diffusivity equation. Implications on practical applications such as well testing are addressed.
Experimental Investigation of Sanding Propensity for the Andrew Completion
Authors: Venkitaraman A. , Li H. , Leonard A. J. , Bowden P. R. 
Published: December 2007

Abstract
One of the main concerns during the completion phase of the planned Andrew horizontal wells was sand production. Analytical models based on inputs from log details and core analyses preferred perforated, cemented liner completions to lessen the likelihood of sand production. To further strengthen this recommendation and to perform a risk analysis of formation failure at the time of underbalance perforation and expected producing conditions, laboratory experiments were conducted on three reservoir core samples selected from two pilot wells. The core samples were perforated with shaped charges under simulated downhole conditions. The perforated core samples were flowed, while monitoring any sand production resulting from the effects of increasing rate, onset of water cut and depletion (increasing effective stress).
The core samples did not show any propensity to produce sand during single-phase oil flow (rates of up to 10 B/D/perforation). When water cut was introduced transient sand production was observed, indicating the production of perforation-generated rock debris. As the percentage water cut was increased, the sand production declined. The core samples did not show any propensity for sand production during depletion testing. The wells were subsequently completed with perforated cemented liners with no sand control. Now, into two years of production no sand problems have been encountered. These experiments are presented as a means of complimenting existing sand prediction models in completion designs for sand prevention.
Improving Recovery Efficiency of Water-drive Channel Sandstone Reservoir by Drilling Horizontal Wells Laterally
Authors: Zhiguo Fu , Qinglong Du , Pingshi Zhang , Bingyu Ji , Weigang Lu 
Published: December 2007

Abstract
Injected water always advances along the bottom of channel sandstone reservoir with high heterogeneity during development by water injection in vertical well. Even if the time of water-drive is very longer, there is still some non-producing thickness at the top of the oil reservoir, which make an unsatisfactory result of recovery. This paper give an example that horizontal well was drilled in the reservoir of only 4m thick remaining oil by using of existing casing pipe of low efficiency vertical wells to make the top remaining oil reservoir produce. The research shows that drilling horizontal well laterally can improve development result of this kind of reservoirs.
Screening and Design Criteria for Steam Assisted Gravity Drainage (SAGD) Projects
Authors: Singhal Ashok K. , Ito Yoshiaki , Kasraie Mahnaz 
Published: December 2007

Abstract
Certain insights into screening and design of SAGD projects, derived from in-depth analyses of three successful field projects in Canada [Tangleflags, Underground Test Facility (UTF) and Imperial Oil's Horizontal Well Pilot I (HWPI) projects] are presented. It was seen that for obtaining attractive oil rates and oil reserves, one must attempt to obtain as large a confined steam chamber, as feasible. Towards this end, one can select suitable sites by carefully scrutinizing various reservoir/geological characteristics for their impact on confinement and size of an expected steam chamber. Important design options include staggering of the injectors (horizontal and vertical) around the horizontal producers in pools with mobile heavy oil; injector to injector spacing so that adjacent steam chambers merge into each other, thereby providing a more efficient mobilization and drainage of oil; and using geo-mechanical effects to advantage, by suitably programming injection and production schedules.
It was seen that for continuous net pay thicknesses of 15 m or larger, encouraging performance during SAGD could be expected. Furthermore, for in-situ oil viscosities of 35 000 mPa.s or lower, staggering of injectors around the producers becomes feasible. In this case, the "steam trap" constraint on production can be ignored during early periods of steaming for obtaining high initial oil rates. If sub-fracture injectivity of steam into the formation is limited, one can attempt an "intermittent SAGD" or a "Single Well SAGD" to maximize returns. Other similar ideas for obtaining an optimal performance are also discussed.
Best Practicable Control Technology Currently Available To Remove Oil From Produced Brine
Authors: Sebesta Ed C. , Winn W.T. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The recommended effluent oil concentration limitation guidelines for "Best Practicable Control Technology Currently Available" (BPCTCA) for produced water discharges are a long term average of 44 ppm with a maximum of 100 ppm. BPCTCA consistent with the Federal Water Pollution Control Act Amendments of 1972 was Pollution Control Act Amendments of 1972 was defined after a thorough analysis of existing treatment system performance in coastal Louisiana and costs for various treatment system modifications.

Introduction
The purpose of the study is to define the "Beat Practicable Control Technology Currently Available" (BPCTCA) to remove oil from water produced with oil and gas consistent with the goals of the Federal Water Pollution Control Act Amendments of 1972 (FWPCAA of 1972). Section 302 (b) of the FWPCAA of 1972 states that assessment of BPCTCA shall include the following factors:The total cost of application of technology in relation to the effluent reduction benefits to be achieved from suchapplication.The age of equipment and facilities involved.The process employed.The engineering aspects of the application of various types of control techniques.Process changes.Non-water quality environmental impact (including energy requirements).
Optimum Development of a Thin Box-Shaped Reservoir with Multiply Fractured Horizontal Wells
Authors: Lietard Olivier , Hegeman Peter 
Published: December 2007

Abstract
Very low permeability reservoirs are commonly developed with hydraulically fractured wells. Quite often, drilling costs must be reduced and/or the number of slots on an offshore platform is limited. Vertical wells are then replaced by a horizontal well with a set of parallel, equal size hydraulic fractures. A recurrent question concerns the productivity index of this multiply fractured horizontal well.
Simple analytical expressions of this index have been provided by Mukherjee et al.1 and later corrected by Lietard et al.2 They however underestimate to a large extent the actual performance of this type of well.
The present paper proposes a much better definition of the productivity index of multiply fractured wells. It is based on the usage of Dietz’ shape factors3 for vertical wells centered in independent box-shaped drainage areas of equal size in the considered reservoir. For this purpose, Gringarten’s work4 about shape factors for hydraulically fractured wells has been revisited, and corrected equations are presented in this paper.
Selectively Placing Many Fractures in Openhole Horizontal Wells Improves Production
Authors: Love T. G. , McCarty R. A. , Surjaatmadja J. B. , Chambers R. W. , Grundmann S. R. 
Published: December 2007

Abstract
This paper summarizes stimulation results from an openhole horizontal well that was treated with a new fracturing process called hydrajet fracturing. With this process, operators can accurately place many fractures at different locations in a horizontal well without using sectional isolation techniques. In particular, the process uses high-pressure jetting to concentrate fracturing energy at a precise fracture location. Surface and downhole pressure recorders, flow recorders, and tracers obtained pertinent data for further study of the process. The well in this study was hydrajet-fractured with acid.
This study demonstrates that openhole horizontal wells can be hydrajet-fractured effectively and economically.
Horizontal Drilling in Miocene thin Sand of the Lake Maracaibo
Authors: Partidas Carmen 
Published: December 2007

Abstract
With a long history of drilling vertical wells aiming at producing hydrocarbons from several different pay intervals, the Lake Maracaibo Basin has reached a stage of maturity that requires resorting to new technologies to overcome problems normally found in basins at this stage of development. Horizontal drilling provides a means to increase recovery, drain individual sands more efficiently and thoroughly, avoid negative effects like water coning or finguering resulting from fast production, and, shortening producing periods by recovering reserves more rapidly. Miocene sands where this technology was applied, presented several intervals of unconsolidated sands of variable continuity, pay intervals with most frequent thickness in the ten to twenty feet range and reservoir pressures predominantly at hydrostatic or below hydrostatic values.
The horizontal drilling program in the Lagunillas Lago Production Unit of Maracaibo was initiated in 1995. To date, 91 wells have been drilled with a total horizontal footage of 94,173 feet drilled. Results can be assessed only through an economic analysis in which time plays an important role. Pay out. Profit to Investment Ratio and Net Present Value properly discounted, are some parameters used in the evaluation of horizontal wells. For instance, of the 18 horizontal wells drilled in 1996, 42% show less than a 2-year pay out. 42% a pay out of 2 to 4 years and, 16% a pay out of more than 4 years. Profit to Investment Ratio for the same time period was distributed as follows: 68% greater than 2, 21% between 1.5 and 2, and 11% less than 1.5.
Future horizontal drilling will be dictated by volumes of Remaining Reserves combined with performance of vertical wells in the same area. Vertical wells showing high water cuts will be considered for replacement by horizontal wells, provided that Remaining Reserves justify investment. Because of the low pressures in many reservoirs, formation damage by drilling fluids will be carefully assessed. Dual horizontal drilling in heavy oil reservoirs, in combination with steam injection, will be an important consideration in future programs.
Surveying and Analyzing Injection Responses for Patterns with Horizontal Wells
Authors: Fedenczuk Leon , Hoffmann Kristina 
Published: December 2007

Abstract
This paper presents a novel method for visualizing injection responses in patterns that include horizontal and/or vertical wells. Horizontal wells can respond to half a dozen or more vertical injectors. Understanding fluid communication between the horizontal well and the surrounding injectors is essential to estimating the effectiveness of the waterflood and helps to predict responses to the waterflood. Armed with the understanding of responses, we can optimize injection patterns, improve production rates, and achieve more efficient oil recovery.
Comparing the produced rates of oil and water to the injected water demonstrates fluid communication through a reservoir. However, typical oilfields can exhibit complex geology in patterns, accidental schedules of wells and/or random changes in the injection and production rates. Together with the shear volume of data, manual analyses may lead to ambiguous and biased associations between producers and injectors. The technique presented in this paper provides a rigorous and unbiased approach. It is based on the Spearman rank correlation between the injected and produced rates over a period of time. The correlation and the time lag between the injection and the associated production rates allow us to compress these two series of rates into a set of two simple parameters.
The advantage of the approach outlined in the paper is the capability to do a quick analysis and interpretation of fields under the waterflood, with a large number of injectors and many years of history. Furthermore, the analysis is based only on the ready available injection and production history. The development of the methodology was originally intended for injection optimization. It may however play an essential role in studies to locate the under-performing fields that may represent the acquisition targets.