bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Dynamic 3-D Reservoir - Both Hydraulically and Geomechanically
Authors: Heffer K.J. , Koutsabeloulis N.C. 
Published: December 2007

Abstract
Reservoirs are dynamic, not only in the sense that fluid pressures and saturations change during development life, but also in the sense that geomechanical states and therefore absolute permeabilities alter with time. Evidence for this is in the strong correlation between the directionality of reservoir flow in waterfloods and the local orientation of horizontal earth stresses. In addition the correlation coefficients between flow rate histories at pairs of wells in a number of fields indicate that reservoir dynamics have at least some component linked to geomechanics. Coupled geomechanical-fluid flow numerical modelling is able to explain some of the observations and so offers an improved predictive tool for planning and managing waterfloods and determining optimal locations for infill wells. Such modelling is now at the stage when it can soon start to be applied to 3-dimensional problems.
Introduction
One of the most important parameters in designing the pattern of wells for waterflooding a reservoir is the directionality in horizontal flow; i.e. any preferred lateral direction for fluid flow across the reservoir. Recent studies have revealed a strong correlation between the directionality of reservoir fluid flow and the local orientation of modern-day maximum horizontal principal earth stress (Shmax). Even more surprisingly, this correlation holds equally well for the set of reservoirs which would not normally be described as "naturally fractured" as it does for those that obviously do contain open, conductive natural fractures. It has been conjectured that this correlation is explained by coupled processes m which the conductivities of natural fractures and faults (of which, generally speaking, there is a large population even in unfractured reservoirs) are altered by the geomechanical changes induced by the flooding process. According to the concepts of the metastability and self-organized criticality of the lithosphere, perturbation by even minor stress changes is likely. This conjecture was given credence by coupled numerical modelling of the geomechanical, fluid flow and heat flow processes involved in waterflooding; generic modelling of the progress of a flood front around a single injector well gave rise to similar patterns of directionality as observed in the aggregated field data. Coupled modelling therefore provides a potential new tool for improved design of waterfloods and infill drilling projects; this will be further demonstrated later in this paper.
Development of HP-HT Coiled Tubing Unit
Authors: Maroli R. , Tambini M. , Wilde G. , Craig S. 
Published: December 2007

Development of HP-HT Coiled Tubing Unit.

Abstract
This paper presents results on the feasibility studies, development and first operations of a coiled tubing unit for use in deep high pressure and high temperature oil wells.
The coiled tubing unit was required to work primarily in the Villa Fortuna/Trecate oilfield in Northern Italy. This field had an initial reservoir pressure of about 14500 psi at 18400 ft TVD and static wellhead pressure of 8500 psi; reservoir temperature is 330 F. A coiled tubing unit was required to carry out operations such as acid/solvent treatments, washing, fishing etc.
This paper is focused in the following items:
laboratory and field tests, performed for the evaluation of stripper rubber life at 10.000 psi, and tubing failure through ovality.
The modifications of a coiled tubing unit standard components.
Pipe design optimisation with stress analysis software to ensure that the operations could be carried out with the tubing in its maximum allowable ovality state.
Quality control: new tubing ovality monitoring and data acquisition system for coiled tubing O.D. measurement.
Furthermore the first "live" well operation and the first operation in Villa Fortuna/Trecate field are reported in the paper.

Introduction
The development of the Villafortuna Trecate field led to the necessity of extending the operations performed with standard coiled tubing unit in high pressure and high temperature wells.
On the basis of this industry need a research project started in 1990 for the design and construction of a coiled tubing unit able to perform the following operations in high pressure and high temperature wells:
asphaltene deposit removal with chemical solvent;
matrix stimulation by acid placement across the perforations;
fishing operations;
displacement of high density brines in emergency well control situations,
At the time of the project the main operative limits for a standard coiled tubing unit were: maximum wellhead working pressure 5000 psi, maximum depth 17.000 ft, maximum pulling force 25.000 lbs. The industry standard injector head of that time had a nominal pulling capability of 40.000 lb, however, under field conditions slippage of the tubing within the gripper system often occurred when pulling forces exceeded 25.000 lb. It was clear that such behaviour is the result of differing structural compliance for the tubing and the injector chains. Furthermore the wear capability of the stripper rubbers was long enough only with a wellhead pressure less than 3000 psi.
In order to have access at Villafortuna Trecate wells the operating limits had to be increased: in particular the maximum wellhead working pressure had to be 10.000 psi, the maximum depth 22.000 ft, maximum pulling force 60.000 lbs. In order to perform the operations in a safe condition the stripper rubbers wear capabilities had to be satisfactory at 10.000 psi and 240 F.
P. 219
Gas Reservoir Performance in Abnormally High Pressure Carbonates
Authors: Chu Wei-Chun , Kazemi H. , Buettner R. E. , Stouffer T. L. 
Published: December 2007

Abstract
Two-dimensional r-z reservoir simulation and tank material balance were used to develop a prediction technique for gas reservoir performance in abnormally high pressure reservoirs. It is shown that p¯/z¯ versus Gp plot is very sensitive to the variability of the effective compressibility, ĉe. Nevertheless, our technique gets around this problem and, with availability of reliable reservoir history data, accurately predicts the reservoir performance and original gas in place, especially in single-well reservoirs such as the Cotton Valley reefs in East Texas. The calculations presented in the paper are simple and easy to use.
Diagnostics and Improvement of Wellhead Gas Metering: A Case Study
Authors: Shen J. J. S. , Ting V. C. , Holzer R. A. 
Published: December 2007

Abstract
This paper presents a case study of improving the gas metering facilities and operation in the Indian Basin Field, New Mexico. Chevron operates 12 gas wells, each producing 3 to 6 MMSCFD, in the field. The wellhead meters, built about thirty years ago, basically consisted of 3" orifice meters with upstream out-ofplane elbows and other fittings that measured wet gas. Chevron began to examine the production and metering conditions three years ago to improve the measurement accuracy. Since the old meter piping system does not fit the specified configurations in the API 2530/A.G.A. 3 standard, the only way to ascertain the flow condition was to survey the velocity profiles inside the meter. Thus, a directional pitot probe was used to traverse the pipe and no significant swirls were observed. However, the wet gas condition and internal roughness of the old meter tubes were serious concerns. A dehydration unit was constructed to lower the moisture content of the gas and a new orifice meter with electronic measurement was installed downstream of the existing facility. A comparison of the two orifice meters showed that the wet gas measured by the old 3" meter with out-of-plane elbows was approximately 3% lower than the drier gas measured by the new meter. Possible reasons for this metering deviation are discussed in the paper.
Reservoir Properties and Stabilized Gas Well Performance From Short Deliverability Tests
Authors: Hashem Yousef Kh. S. , Kazemi H. 
Published: December 2007

Abstract
Numerical simulation was used to verify that properly conducted deliverability tests in gas wells would yield reliable values for permeability, skin factor, non-Darcy parameter, and stabilized well performance coefficient. Furthermore, the correctness of pseudostabilization time, used in obtaining the stabilized performance coefficient, was verified. Pseudostabilization flow time should not be mistaken for the stabilization time, which is defined as the time corresponding to the onset of pseudosteady-state flow behavior. Stabilization time is 2.52 times greater than pseudostabilization time for radial flow.
The boundary condition at the wellbore included the use of chokes to control flow rates. Wellbore storage and non-Darcy flow effects were also included in the numerical simulation. Both Rawlins and Schellhardt empirical equation as well as the theory-based pressure drawdown equation were successfully used in deliverability calculations using the numerical simulation results.

Introduction
Gas well deliverability tests are multirate tests consisting of three or more flows with rates and pressures recorded as a function of time. These tests are required by state regulatory agencies for proration purposes. Furthermore, these tests can provide information useful for reservoir forecasting, skin damage evaluation, and establishing a base performance curve for future comparisons.
The basic work towards development of a practical test was carried out by Pierce and Rawlins. Rawlins and Schellhardt introduced the concept of backpressure testing using the flow-after-flow test. Cullender presented the isochronical test as an empirical method and Katz et al. presented the modified isochronal test consisting of equal flow and shut-in periods.
Rawlins and Schellhardt historical backpressure (or gas deliverability) equation is:
(1)
From integration of quadratic form of Forchheimer equation (known as non-Darcy flow equation) one can obtain the following steady-state solution:
(2)
Where:
(3)
(4)
(5)
(6)
It is well known that during transient flow the following analog of slightly compressible flow generally applies to gas wells (especially for p &lt; 2000 psia):
Where:
(7)
(8)
Eq. 7 can be written in a form similar to Eq. 2 as follows:
P. 393
Comparative Evaluation of The Strongly Implicit Procedure (SIP) for Gas Reservoir Simulation
Authors: Steen H. Dale , Ali S.M. Farouq 
Published: December 2007

Abstract
The chief aim of this study was to ascertain the best method for gas reservoir simulation. The research was principally concerned with an evaluation of the new SIP algorithm for solving the matrix problem arising from the application of the implicit, completely implicit and modified implicit difference techniques to the nonlinear partial-differential equation for the flow of partial-differential equation for the flow of a real gas in two dimensions, expressed in two different forms, utilizing the original and the transformed variables, respectively. A number of conventional difference methods were also tested for comparison purposes. The reservoir considered in the simulations was assumed to have a uniform permeability distribution in one set of runs, and a random permeability distribution in another set.
The equations resulting from the application of the completely implicit scheme were solved by both SIP and SOR (successive overrelaxation), in order to evaluate the speed of convergence using the two methods. In addition, a series of numerical experiments was carried out using the SIP algorithm in order to study the effect of the number of iteration parameters on the number of iterations required for convergence, the rate of convergence, and the material-balance error incurred.
Curves of the material-balance error as a function of the simulated production time were obtained for all the runs conducted, using the schemes tested.
It was found that all of the explicit schemes (forward difference, Barakat-Clark, ADEP, and Dufort-Frankel) tested suffered from time-step size limitations and increasing material-balance errors with time. The implicit schemes, in particular, the modified-implicit scheme, is therefore recommended. Computational results show that the SIP algorithm is far superior to the SOR or ADIP methods with regard to the time-step size and material-balance error. The optimized SIP algorithm, although involving more computational work per iteration requires fewer iterations to converge than SOR, for a given accuracy. Furthermore, the number of SIP iteration parameters should be optimized where feasible, since in some cases (e.g., the completely implicit scheme) it may have an important effect on the number of iterations required for convergence.
Production Forecasts for a Heterogeneous Gas Reservoir Using an Integrated Simulation Model
Authors: Geppert E. C. J. , Dimmer Kimberley , Fischer Brian 
Published: December 2007

Abstract
A 3 dimensional reservoir simulation model of the Harmattan East gas condensate field was linked with a surface facilities model in order to predict future gas deliverability and evaluate further capital expenditures, such as additional compression or horizontal infill wells. Using a more rigorous approach for this complex reservoir resulted in an increase in the estimated original gas in place, and allowed surface facility decisions to be tied to the infill drilling program. This model yielded more accurate results than a tank model because of the large permeability and pressure variations within the field.
Planning the First Horizontal Well for the Shallow Oil Zone of Elk Hills Field, Kern County, California
Authors: Hardin James , Martin Jim , Davidson Joe , Paulk Martin 
Published: December 2007

Abstract
A horizontal well was successfully drilled and completed in the Shallow Oil Zone (SOZ) of the Elk Hills field (Naval Petroleum Reserve #1), Kern Co., California. The reservoir formation is Pliocene age, low pressured, unconsolidated sands separated by thin, impermeable shales. The well was drilled to a TVD of 3,998 feet and an MD of 5,648 feet. A 1,111 ft lateral was drilled at 900 and 580 ft of that was completed in two sands. Adjacent wet sands, faults and a thin pay zone were some of the challenges faced in planning and drilling this well.
This paper addresses the reservoir characteristics of the pay zone, planning of the well, and drilling and completion methods that were used. Results of drilling operations, completion operations, production performance and costs are provided, and some comparisons are made to offset vertical wells.

Introduction
Horizontal drilling has proven itself in recent history as a highly profitable alternative to conventional vertical drilling. In a paradigm shift, horizontal wells have become common in some applications, displacing vertical wells.
The Shallow Oil Zone at the Elk Hills field was originally developed through vertical drilling as a strategic reserve under the management of the Department of the Navy (now under the U.S. Department of Energy). Of the estimated 1.6 billion barrels of oil in place in the SOZ, approximately 450 million barrels have been produced since the early 1900s. The SS-1 (Sub Scalez One) is the most significant oil producing sand within the interval referred to at Elk Hills as the SOZ. Gravity drainage and low reservoir pressure in the SS-1 sand have led to a low reservoir decline rate and long productive well lives. This is especially true along the southern flank of the anticlinal structure which comprises the primary trap for oil and gas in the SS-1 sand. Realizing this, recent planning for the SOZ has focused on accelerating recovery and increasing recoverable reserves.
The SS-1 sand at Elk Hills has reservoir characteristics similar to other reservoirs that have been exploited successfully by horizontal well technology. Initial evaluation suggested that horizontal wells could economically accelerate and increase recovered reserves if several challenging obstacles could be overcome.

Reservoir Characteristics
The SS-1 is a member of the Pliocene San Joaquin Formation and has been divided into twelve sublayers within the eastern portion of the field.
These sublayers are separated by thin shales which serve as vertical seals through most of the productive area. Gas/oil and oil/water contacts vary between sublayers. Individual sublayers vary considerably in thickness across the field and pinch out locally, and to the west entirely, along trends easily defined by well logs.
P. 185
Case History of the 31S Peripheral Waterflood Project, Stevens Zone, Elk Hills Field, California
Authors: Starcher M.G. , Engineer R. , Nelson M.L. , Wilson M.L. 
Published: December 2007

Abstract
This paper summarizes and contrasts the peripheral waterflood performance of two reservoirs that constitute the 31S project in the Elk Hills Field, Kern County, California. The combination of light oil (36 API), favorable mobility ratio (0.4) and an anticlinal structure makes these sandstones good candidates for peripheral flooding. From 1978 until December 1995 cumulative water injection in the 31S project was 371 million barrels and cumulative recovery was 155 million barrels of oil. Early initiation of a pressure maintenance project including 117 BCF crestal gas injection has improved oil recovery. The Main Body 'B' reservoir is exhibiting a distinctly layered response with high recovery from its more permeable layers and lower recovery from tighter layers. This flood has the potential for bypassed reserves. The Western 31S reservoir has moderate to high dips and is exhibiting a less layered flood response and very efficient displacement. The gravity drainage component from the secondary gas cap is playing a significant role in the process. Aside from high recovery, the project is remarkable in demonstrating successful resaturation of a secondary gas cap. Future work will include refinement of original-oil-in-place (OOIP) estimates with a new petrophysical model and improving tight layer management by pattern waterflooding and increasing productivity and injectivity with stimulation treatments.

Introduction
In the literature there are a few papers describing peripheral waterfloods. The 31S project in the Elk Hills Field, California provides an opportunity to study a large, mature peripheral waterflood and to see the effects of a long term injection into two very different reservoirs.
The Elk Hills Field is located about 20 miles WSW of Bakersfield, California (Fig. 1). It is one of the 10 most productive oil fields in the United States with a cumulative recovery of over one billion barrels to date. The Main Body 'B' (MBB) and Western 31S (W31S) sands occur at an average depth of 6,500 ft. The zone was discovered in 1941. The field was held in reserve and only periodically produced until 1976 when it was opened up to production at capacity. The current production from the MBB and W31S reservoirs is about 11,300 BOPD and 3,500 BOPD respectively.
The mechanism for primary production from for the MBB and W31S reservoirs was a combination of solution gas, partial water drive, and some contribution from gravity drainage. The primary recovery factor was estimated to be in the range of 12% of the OOIP.
Since the onset of the exploitation, secondary recovery was considered essential for the MBB and W31S reservoirs.
P. 227
A Description of Summer and Winter Environmental Conditions within Cook Inlet, Alaska
Authors: Nelson William G. , Whitney J.W. 
Published: December 2007

Abstract
In spite of severe environmental conditions, successful oil exploration, production and shipping have occurred in Cook Inlet for over 30 years. This paper combines the results of an extensive literature search as well as the results of a continuing study of the winter ice conditions in Cook Inlet to describe the summer and winter environment of Cook Inlet.
Cook Inlet, located in south-central Alaska, is unique in that it has a very high suspended sediment load, high tides (10 m), a moderate snow fall and an air freezing index of 1400 C days per year. These conditions combine to cause low visibility, extreme tidal currents (8 kts) and unique modes of ice generation within the inlet.
The major mode of formation of floating ice is identified as slush ice formation. The slush then coalesces in the turbulent waters to form various ice features. Ice features with depths greater than two meters that formed in less than seven days are described. Ice buildup on shore based structures results in significant downward and upward vertical forces as well as potential horizontal forces.
Information summarized in this paper will be useful when analyzing tidal currents and ice forces on offshore and nearshore structures. Information regarding tidal currents and ice conditions within the inlet will also be beneficial in the avoidance of or cleanup of product spills in the inlet.

General Description of Cook Inlet
Cook Inlet is a large tidal estuary located in Southcentral Alaska at 610 north latitude and 1510 longitude. Cook Inlet extends from the North Pacific Ocean approximately 350 km into Southcentral Alaska. The inlet varies from more than 130 km wide at its southern mouth to less than 15 km at the northern extremity of Knik Arm. The Aleutian and Alaska Mountain Ranges border the inlet to the west and the northwest, the Talkeetna and Chugach Mountains to the northeast, and the Kenai Mountains to the east and southeast.
This estuary is divided into three subareas, the head region, upper inlet, and lower inlet. The head region includes Knik and Turnagain arms which are relatively shallow and each approximately 60 km long. The major constricting point, about 25% of the way down the inlet from the north and known as the Forelands, is the boundary between the upper and lower inlet. Water depths in the upper inlet reach 30 to 40 m with a narrow 100 m deep channel through the Forelands. Water depths in the lower inlet reach 150 m.
Four major islands exist in Cook Inlet. The largest two are Kalgin Island, located in the northern part of the lower inlet, and Augustine Island, a volcanic edifice in the southwestern corner of lower Cook Inlet. The other two islands, Chisik in the lower inlet on the west, and Fire Island, in the upper inlet, are largely extensions of the mainland.
P. 381
Keys to Improving Environmental Performance
Authors: Moreau Roland L. , Raught Deborah L. 
Published: December 2007

Abstract
Environmental protection is a mainstream issue in today's society. Both internal and external drivers motivate the oil and gas industry to continuously improve environmental performance. Companies are integrating environmental considerations into their business plans to a greater extent, and are directing proportionally more resources toward managing these issues.
This paper addresses several environmental management focus areas in Exxon's domestic E&P sector to: 1) manage risks, 2) ensure compliance, 3) improve performance, and 4) assist in the development of balanced legislation and regulations. Specific examples of Production Department programs are discussed, along with keys to success for continued progress in improving performance.
The Management of Healthcare Reform in a West African Oil Company
Authors: Simpson Stephen R. 
Published: December 2007

Abstract
This paper describes how Chevron Nigeria Limited (CNL) provided health care to its 1,700 employees and their families prior to June 1992. A strategic appraisal of both internal and external issues suggested areas of healthcare reform, and the benefits that might be delivered to stakeholders. These are described.
Cultural and other inhibitors to change were highlighted, and methods to overcome them suggested. This paper confirms that health care reform is a sensitive area, and any change should be effected with caution.