bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of an Economic Incentive Factor in the Correlation and Projection of Discovery and Production Rates of Natural Gas in the Lower 48 States
Authors: Linden Henry R. , Parent Joseph D. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
An economic incentive factor has been found whose trend has closely paralleled that of annual gross additions to proved reserves of natural gas in the lower 48 states for the last 20 years. This factor is the weighted average price at the well for hydrocarbons (natural gas and oil) divided by the square of the average cost of drilling and equipping new wells (oil, gas and dry). For convenience, the well cost is put on a relative basis referred to the 1946–50 average. All prices and costs are expressed in constant 1972 dollars. The economic incentive factor has been a leading indicator of discovery rate by 2 years.
The factor can be used to modify the IGT model for U.S. natural gas discovery and production to make it responsive to yearly changes in economic incentives to search for new supplies. Using the modified model and a projected trend of the economic incentive factor, future natural gas supplies in the lower 48 states have been calculated. Some projections have also been made on the basis of three possible scenarios in terms of annual possible scenarios in terms of annual gross additions to proved reserves.
All indications point to the need of promptly reestablishing and maintaining promptly reestablishing and maintaining much higher annual additions to proved reserves by sharply increasing the weighted average wellhead price of oil and gas. Otherwise, production of natural gas in the lower 48 states will decline soon.
Note: This study was based on historicaldata for the period 1946 - 1972.Since its completion, natural gas discovery and production data for 1973 have become available. None of the correlations or projections would be materially affected by inclusion of these new data, which are discussed briefly at the end of the text

Introduction
The United States has now had 6 years of inadequate natural gas discoveries in the lower 48 states and 3 years of substantially less than required natural gas production. production.
LNG Imports and FPC Regulation
Authors: Mathura Randolph E. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The United States Federal Power Commission's approval must be obtained for the importation of LNG, which has been considered as natural gas, and for the transportation and resale of imported LNG in interstate commerce and the facilities associated therewith. Longterm base-load LNG imports are a potential source of significant potential source of significant supplemental natural gas supply. The required applications for approval of these imports must contain certain descriptive information and are processed, reviewed, and decided according to administrative procedure. The Commission has approved procedure. The Commission has approved several of these applications to date and has decided some of the issues raised therein.
The views expressed herein are the views of the author and do not necessarily reflect the views of the Federal Power Commission or its staff.

Introduction
The technology for the production and handling of liquefied natural gas (LNG) is well established. The benefit of liquefaction is the volume reduction advantage in converting from the gaseous to the liquid phase. This affords a greater degree of flexibility for the transportation and storage of natural gas in many areas of gas utility operations. In addition, liquefaction makes possible the transportation of overseas gas reserves to the United States. These potential LNG imports could have a potential LNG imports could have a significant impact on United States gas supplies.
United States LNG imports can be characterized as short-term and long term.
Plunger Lift Correlation Equations And Nomographs
Authors: Beeson Carrol M. , Knox Donald G. , Stoddard John H. 
Published: December 2007

Abstract
The operation of the 2-in. and 2 1/2-in. expanding cycle-controlled plungers, has been placed on a quantitative basis by means of equations obtained from correlations of field data gathered throughout the United States. For each size plunger, three basic correlation equations express the requirements of gas and pressure as functions of size load and depth. A fourth equation gives the maximum production rate in terms of the same variables.
Using the equations, nomographs have been constructed to permit graphical solution of the problem of plunger lift performance for a given well. The solution is obtained by plotting the "(efficient) operating line" for the well, thereby relating the size load to the gross production rate. Examples of use of the nomographs have been included.
Methods have been described in the Appendix that were used in obtaining the correlation equations from four plots of data for each size plunger. The data represent the operation of plunger lift in 51 wells (or well conditions) with 2 7/8-in. tubing and 33 wells (or well conditions) with 2 3/8-in. tubing. In plotting the figures to determine the correlation equations for pressure build up, data were used only from the 38 wells with 2 7/8-in. tubing in 7-in. casing and the 22 wells with 2 3/8-in. tubing in 5 1/2-in. casing.
No measurable distinction was found between wells operating on formation gas alone and those operating on additional circulated gas. The wells (or well conditions) were about equally divided between these two types. Although it is believed that tailpipes lower the efficiency of plunger lift, the data from the few wells with tailpipes did not show any trend with tailpipe length, providing all calculations were made for the bottom of the tailpipe. Water cuts varied from 0 to 89 per cent, with an average of 23 per cent, and water cut was not found to be important in the operation of plunger lift. Oil gravities were mainly in the mange from 25 to 50 API, averaging 36 API, and no correlation was found between oil gravity and the gas or pressure requirements.

Introduction
One of the most efficient methods of producing oil involves the use of the expanding cycle-controlled plunger. The expanding segments make contact with both the small and large portions of regular API tubing strings, thereby forming an effective seal between the lifting gas and the lifted liquid.
Production Strategy Yields Unique Perforating, Cost-Efficient Multilateral Drilling Solution in the Beryl Field
Authors: Sadek Hani , Williams Charles R. , Smith Michael 
Published: December 2007

Abstract
The Mobil-operated Beryl Field in the North Sea has been producing from the Alpha and Bravo platforms in excess of 20 years. As the field has matured, conditions have changed, necessitating investigation of new solutions to meet the resulting challenges. This paper will discuss the design, development and testing of a new multilateral-type drilling and completion system that was developed to economically address specific drilling and producing requirements. Investigation of various types of completion strategies determined that the general concepts of multilateral technology would have application in providing for field needs. However, currently available technology presented several problems. While access and maintenance of production from two wellbores from one well slot can enhance economics and project risks, existing multilateral technology would significantly increase costs of projects and introduce significant operational risks.
A solution that allows full-bore access to laterals and capability to resume production from the main bore by perforating a sealed hollow whipstock was developed to address one of the Beryl Field needs. Technological advancements of the system include a specially designed whipstock/packer configuration and a specific perforating gun and charge. The equipment has been fully developed, tested and is now available for field application in the North Sea. The new system has the capability of meeting Mobil North Sea, Ltd. objectives of economically maintaining production from mature wells without subjecting side-tracked wellbores to unnecessary risks or access constraints that could compromise project efficiency.
P. 399
Experimental Fireflood - Carlyle Field, Kansas
Authors: Elkins L.F. , Skov A.M. , Martin P.J. , Lutton D.R. 
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
Pilot tests of forward combustion were conducted in 35 to 45 ft oil-saturated sand overlying 100 to 125 ft water-saturated sand in the Bartlesville sand at a depth of 860 ft. Ignition and maintenance of combustion were achieved easily. Cold wells typically produced 0.5 to 2 B/D of 700 cp 19 degrees API oil. After heat breakthrough, and in some cases after various stimulation treatments, some individual wells had peak production rates of 40 to 60 BOPD. However, peak production rates of 40 to 60 BOPD. However, typical average production rates of wells were 3 to 10 BOPD. Post combustion coring in the initial 2.5 acre 5-spot pilot indicated much of the burning occurred in the water sand which contained 5 to 15 percent residual oil saturation - enough oil to support combustion.
Many different attempts were made to increase productivity of cold wells. These stimulations included injection of various solvents, de-emulsifiers, acids, etc. into the sand, and steam soak, burn treatment, and fracture treatment. Although some of these efforts resulted in significant increases in oil production rate, generally, the effects were short lived. We were unsuccessful in achieving sustained oil production rates by forward combustion which production rates by forward combustion which would indicate profitable operation on an expanded multiple pattern basis.
With lack of success in forward combustion, as a last resort, we converted two ignited air injection wells to production and two cold producing wells to air injection for a test of producing wells to air injection for a test of reverse combustion. The better of the two hot producing wells achieved a sustained rate of producing wells achieved a sustained rate of 25 BOPD with an instantaneous combustion GOR of about 40,000 cu ft/bbl. The cumulative average GOR of this well was 68,000 cu ft/bbl. Tests of an observation well 100 ft from this producing well indicated much of the combustion producing well indicated much of the combustion occurred in the water zone. Later, tests of the observation well, backflow tests of the two cold air injection wells, and tests of other wells indicated that spontaneous ignition had occurred within 8 to 10 months in the vicinity of the injection wells. This precludes reverse combustion operation in this reservoir at any economically attractive well spacing.

Introduction
Starting in February 1963 and continuing into 1966, Layton Oil Company operated an underground combustion test in the Bartlesville sand, Carlyle Field, Allen County, Kansas. Results of this test which included 4 air-water injection wells and 12 producing wells in an 11-acre area were reported by M. W. Smith in 1966.
Heavy Oil Recovery by Steam-Driven Hydrocarbon Slugs from Linear Porous Media
Authors: Alikhan Abbas A. , Ali S.M. Farouq 
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
This work was principally concerned with an experimental study of oil recovery from a porous medium by the injection of a light hydrocarbon slug, followed by a steam slug, which is in turn driven by a conventional waterflood. An attempt was made to simulate the experiments by use of a cell model. The experiments involved fluid displacements in two glass bead packs having a rectangular internal cross-section of 1.75 × 3.75 in and 48 in length, overlain and underlain by 1.5 ft thick sand packs to simulate the adjacent formations.
The core initially contained a residual oil saturation or a high initial oil saturation, corresponding to the irreducible water saturation. Drakeol 33 and Drakeol 35 (viscosities of 152 and 209 cp, respectively) were employed as the inplace oils, while isooctane, Soltrol C, Kendex 0837, Drakeol 9, Drakeol 15, and three mixtures of Soltrol C and Drakeol 33, Kendex 0837 and Drakeol 9, and Drakeol 9 and Drakeol 35 (viscosities of 0.5, 1.3, 11.3, 23.4, 49.4, 6.4, 17.4, 73.3 cp, respectively) were used as the light hydrocarbon slug materials. Light hydrocarbon slug sizes of 5, 10, and 25% PV were employed, while the steam slug size ranged from 19 to 66% PV, with an average of 35.7% PV. The steam injection rate ranged from 11 to 150 ft/day.
It was found that the light hydrocarbon slug injected prior to the steam slug in a core initially containing a residual oil saturation improved the oil recovery as compared to a straight steam slug run. The light hydrocarbon, in view of the prevailing adverse mobility ratio, mixes with the original inplace oil, and helps to lower its viscosity. This viscosity is further reduced by the heat from the injected steam slug, leading to an improvement in the mobility ratio, and hence an improvement in the displacement efficiency. A large proportion of the light hydrocarbon slug is recovered by the steam distillation effects. It is concluded that from the recovery ratio (volume of oil recovered divided by hydrocarbon slug volume) point of view, it is advantageous to use a low viscosity light hydrocarbon slug, and a small slug size. The optimum slug size depends on the in-place oil, as well as the steam slug size, for a given steam temperature.
The temperature profiles and the heat loss rate measurement indicated that the combination, light hydrocarbon slug-steam slug, process utilizes the maximum amount of heat injected, hence increasing the thermal efficiency of the process. process.
Principal Permeability Determination from Multiple Horizontal Well Tests
Authors: Muñoz Alberto , Ehlig-Economides Christine , Economides Michael J. 
Published: December 2007

Abstract
Horizontal wells have forced a reconciliation with the concept of permeability anisotropy: vertical-to-horizontal and horizontal-to-horizontal. The former, if favorable, may indicate whether a horizontal well is attractive compared to a vertical well; the latter is important in well orientation. While other authors and we have postulated at least a qualitative relationship between stress and permeability orientation and we have suggested that wells should be oriented normal to the maximum stress/permeability orientation, it is often neither easy nor possible to measure stresses. In fact substantial permeability anisotropy has been found even in formations where stresses approach isotropy. In unconsolidated or loosely consolidated formations stress measurements may not even be plausible. Productivities deviate substantially among wells in the same reservoir and the well orientation has been considered as a major reason.
There is, therefore, a compelling rationale to detect and measure permeability anisotropy. Ideally this should be done before a horizontal well program is initiated in a reservoir, but if this is not possible, shortly thereafter. Both vertical and horizontal pressure interference testing have been used for permeability determinations. Under the assumption that the geometrical mean permeability, k¯, is available from a vertical well test, other authors have suggested that tests in two horizontal wells, forming an angle between them, can provide the values of the two principal horizontal permeabilities. We are suggesting a further development requiring only the linear flow regime in three arbitrarily-oriented horizontal wells. A field case study illustrates the approach. Using the analysis results, the optimal well trajectory is determined, and economics of the misorientation are computed.
Improved Waterflooding Efficiency by Horizontal Wells
Authors: Popa C. G. , Clipea M. 
Published: December 2007

Abstract
Due to the improvements in the technology of horizontal well construction, there is a tendency to extend the use of horizontal wells for improving the overall efficiency of different recovery processes, including waterflooding. Using horizontal wells in a waterflooding process, a higher sweep efficiency for less cost is expected as opposed to the use of classical patterns by vertical wells. However, the use of horizontal wells is very sensitive to the well pattern designed to operate such a process.
The paper presents an analysis of how the overall efficiency of a waterflooding process is influenced by the well pattern using horizontal wells. Three cases were taken into consideration: first for a pattern using two parallel horizontal wells, one for injection and the other for production, second for a pattern using one horizontal well for water injection and few vertical wells for production, and the third for a pattern using vertical wells for injection and one horizontal well for production.
A two phase two dimensional numerical model was used to make the simulation of the waterflooding process for each case. The results showed that the pressure loss along the horizontal section has a large influence on the sweep efficiency both for using an injection and/or a production horizontal well. Also, the results showed that it is preferable the use of vertical wells for injection and horizontal wells for production rather then the use of horizontal wells for injection and vertical wells for production.
SAGD Operating Strategies
Authors: Nasr T. N. , Golbeck H. , Korpany G. , Pierce G. 
Published: December 2007

Abstract
The steam assisted gravity drainage (SAGD) process has emerged as an effective technology for the recovery of oil from oil sands deposits that are deeply buried for surface mining. In general, the process involves drilling paired horizontal wells, one well above the other and separated by a distance, near the bottom of the oil-bearing formation. The top well is used to inject steam into the oil sands, heating up the oil and allowing it to drain, under the action of gravity, into the bottom well.
The paper first provides a review of the technological advances made in SAGD operating strategies. In addition to the successful field testing at the Underground Test Facility (UTF), the SAGD process has been recently extended to other types of reservoirs. These include reservoirs with lower permeability as compared to that at the UTF site and reservoirs with bottom water transition zones. Challenges facing application of the process in such types of reservoirs will be discussed. Concepts to overcome the challenges will be presented in terms of laboratory studies that have been carried out. The concepts tested include: the use of mechanical means such as drilling vertical drainage channels between paired horizontal wells; combining a vertical well with paired horizontal wells and potential for solvent and gaseous additives in steam (to improve SOR and reduce water requirements). Results provide valuable observations for field scale development of a more robust and economically viable process.
Numerical Investigation of SAGD Process Using a Single Horizontal Well
Authors: Shen C. 
Published: December 2007

Abstract
Recently several articles have been published regarding the innovation and field applications of the Steam-Assisted-Gravity-Drainage (SAGD) process using a single horizontal well for the recovery of heavy oil. In the process, an insulated concentric coiled tubing, inserted into the horizontal wellbore, injects high quality steam to the toe of the well. The steam condensate and reservoir fluids enter the wellbore and flow back along the annulus to the heel to be produced.
There remain some arguments on whether the SAGD mechanism is working in field operations, and on what oil rates can be achieved in the long run. In an attempt to answer these questions, numerical simulation studies were pursued in the present work. The studies focused on three major aspects: (1) the possible counter-current fluid exchange pattern between the reservoir and the well; (2) the means that could be exploited to promote the initiation of a steam chamber; and (3) the potential oil rates that could be expected under possible field operating conditions. The results showed that the presence of small capillary pressure near a horizontal wellbore is a physical constraint preventing counter-current exchange of steam and oil. It was also demonstrated that vertical undulation in well-profile or a certain level of formation dilation around the wellbore could potentially overcome the capillary pressure constraint and promote the initiation of a steam chamber under field operating conditions.
Application of a Non-Equilibrium Reaction Model for Describing Horizontal Well Performance in Foamy Oils
Authors: Saputelli B. Luigi A. , Canache P. Carlas M. , López Elías 
Published: December 2007

Abstract
Improving the hydrocarbon recoveries for reserves is actually regarding new technologies and better porous media understanding. Approximately 300,000 millions barrels of additional extra heavy oil were exploitable from Orinoco Belt in Venezuela if suitable explotation strategies were oriented to profit natural mechanisms from existing oil reserves.
The purpose of this paper is to study the sensibility of the activation energy and frequency factor of chemical reaction in heavy oils of the Orinoco Belt in Venezuela. This model accounts for the kinetics of physical changes that occur in the morphology of the gas-oil dispersion. Non-equilibrium reaction model was used in order to model foamy oil behavior observed at SDZ-182 horizontal well in Zuata field. Foamy oil modelling requires the investigation of the activation energy and frequency factor ranges that describes the non-equilibrium reaction model. These ranges were used to obtain a reasonable 3-years history match of SDZ-182 well. Activation energy ranged from 0 to 0.01 BTU/lb-mol and frequency factor ranged from 0.001–1000 1/day for first reaction. For second reaction, activation energy was 50×103 BTU/lb-mol and frequency factor 2,75×1012 1/day. Parameters of the second reaction are more sensitive to any variation than first reaction parameters. This paper describe suitable methodology to match foamy oil behaviour in horizontal wells under cold production and steam stimulation processes.