bluuebunny/crossref_metadata_2025_split huggingface dataset:
The SpliTigatorTM: A Device for the Mitigation of Phase Splitting
Authors: Berger Eric L. , Kolthoff Karl W. , Schrodt James L.G. , Long S. Lynn , Pauley J. Craig 
Published: December 2007

Abstract
Phase splitting at piping junctions in two-phase steam distribution systems results in unequal steam delivery to injection wellheads and interferes with the optimization of injection rates. Texaco's researchers have investigated phase splitting and have devised and evaluated various methods for its mitigation. As a result of these efforts, the SpliTigatorTM, a device for the mitigation of phase splitting, was developed and patented.
The SpliTigator is designed to deliver a specific steam quality to the branch leg of a Tee junction. The SpliTigator delivers consistent steam quality as branch flow rate, system pressure, and inlet flow conditions change. SpliTigator pressure losses are small, allowing numerous devices to be used in series. The use of the SpliTigator has been extended to flow rate and steam quality measurement and other two-phase systems. This paper presents an explanation for phase splitting, discusses the theory behind the design and operation of a SpliTigator, and presents results from both laboratory testing and field applications.

Introduction
The phase splitting behavior which commonly occurs at piping junctions within two-phase piping systems results in unequal distribution of the phases between branches of the junction. In steam distribution systems, inequitable phase splitting results in the delivery of a wide range of steam qualities and mass flow rates to injector wellheads. The SpliTigator is an effective and inexpensive device for the mitigation of phase splitting that has been developed through the joint efforts of Texaco personnel at the Bakersfield Division's Kern River Business Unit and at the Exploration Production Technology Division's Steam Flow Research Facility. An isometric diagram of a SpliTigator is shown in Figure 1. The following summarizes the most significant features of the device.
The SpliTigator:–Controls branch steam quality within a few quality points of design over a wide range branch flow rates, system pressure, and trunk line steam quality.–Creates no additional pressure drop in the main line and requires very little pressure drop in the branch for effective operation.–Requires no moving parts, no periodic adjustments, and little or no maintenance throughout the life of the steam flood.–Is constructed from off-the-shelf piping components as a drop-in replacement for existing branch Tee junctions.
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Surface Facilities Management for Thermal Recovery Processes
Authors: Heiba Adel A. , Barua Santanu , Dutta-Roy Kunal 
Published: December 2007

Abstract
Following the delineation and development of a field, the recovery of oil by cyclic steam stimulation and other thermal methods is controlled by actions taken at the surface. A number of operational variables effect the optimal management of steam stimulation programs. Generally these variables relate to the generation and allocation of steam for injection at production wells. Because the number of variables can be large, the management of steam stimulation programs is seen to require that solutions be found to constrained multivariate optimization problems.
In this paper, a novel and integrated approach is presented to the optimal management of cyclic stimulation programs. The approach combines the use of technologies to simulate the flow of steam in networks and wellbores with an industrially tested variant of the Successive Quadratic Programming algorithm (SQP) for process optimization. Examples are presented that illustrate the ability of the integrated approach to optimize the allocation of steam in distribution systems for which (1) the objective is to minimize the loss of thermal energy in surface piping and wellbore tubing, and (2) the objective is to increase the value of oil production that follows stimulation. Extensions of the approach to more realistic allocation problems are found (i) to require the inclusion of steam generation costs in the formulation of optimization problems, and (ii) to require the incorporation of mechanistic reservoir models for the stimulation of oil production by steam injection.
Delivering Step Change in Performance from Well Construction Teams
Authors: Thorogood J. L. 
Published: December 2007

Abstract
The last five or six years have witnessed a revolution in well construction contracting practices. However, performance has continued to evolve incrementally instead of showing the step change that was predicted by those who advocated such a radical change. There are a number of factors that are likely to have contributed to this situation. The review presented here suggests that the major problem stems from a shortcoming in the way alliance teams are built. It is suggested that a single coherent structure which joins business process, performance measurement and organisational structure into the delivery of an end result will produce the desired step change in performance. Exceptional performance cannot be delivered through structure and process alone. Effective teams require inspired leaders who are capable of directing the team's energies towards challenging, yet achievable, targets.
Cost Effective Horizontal Drilling in the Troll Field Through use of State of the Art Technology and Optimal Operations
Authors: Henriksen N. , Storegjerde D. 
Published: December 2007

Abstract
Less than a decade ago, the thin oil zone of the Troll gas field was almost written off as uneconomical. Extraction of the oil required the drilling of long horizontal sections with high accuracy. This was proven feasible by a 500 m (1650 ft) long horizontal well in 1989 and a second 800 m (2625 ft) horizontal well in 1990. Based on these encouraging results, a development plan was made for a large scale subsea development with 800 m horizontal wells at a budgeted drilling cost of 80 million NOK (12 million USD) or 46 days per well. Today, the highly successful development is producing 250,000 bopd. Moreover, 2,000 m (6,500 ft) horizontal wells are being drilled routinely at a cost of 40 million NOK (6 million USD) or 25 days per well, i.e. half the budgeted cost. Also, planning of multi-lateral wells has started. This paper describes how the efficient use of technology and optimisation of drilling operations have made the significant cost reduction possible.
Pro-Star 2000: Investing in State-of-the-Art Drilling Technology in Order to Reduce the Overall Well Cost Without Compromising on Quality and HSE Issues
Authors: Boering E. , Swart D. , Young T. F. 
Published: December 2007

Abstract
A revolutionary change in the Operator-Contractor relationship through partnering, has created a stable environment for rig and work process improvement. The PT-2000 rig, which commenced operations in 1995, is one of the major results of this strategy.
Teamwork Results in a World Record Length 16 in. Casing String
Authors: Jellison M. J. , Eckroth J. J. , Fulton Jim , Ogren Larry , Moore P. W. , Barber Vance , Vesely Don 
Published: December 2007

Abstract
On 12 April 1996 Louisiana Land and Exploration Company successfully ran and cemented a 14,510 ft string of 16 in. 146.2 lbf/ft (0.907 in. wall) P-110 casing in their Big Horn 4-36 well located in Fremont County, Wyoming. The string had an air weight of over 2.1 million pounds and a hook load of over 1.8 million pounds. This world record feat was the result of a concerted, team effort involving Engineering, Purchasing, Suppliers and Service Companies. The 16 in. casing string played a critical role in drilling the well that had a planned total depth of over 24,000 ft. At the time this paper was written, the final section of the well below the 7-3/4" liner (set at 23,162 ft) was being drilled.
The paper details the complementary roles and contributions of each group involved in this challenging project. The overall well design philosophy is discussed along with a review of the detailed 16 in. casing design structural load and von Mises tri-axial stress analysis. The specialized casing material specifications and manufacturing procedures are presented and related to casing string performance requirements. The paper outlines the casing connector selection criteria and describes the premium connector used on the casing string to withstand the high axial forces and pressures encountered while running the casing and drilling the well. The equipment and procedures used to safely and efficiently run the casing string in a total of only 43 hours from rig up to tear down with 31 hours running time are also described.
The 14,510 ft casing string was cemented back to the surface in a single stage. The paper addresses the importance of the mud properties prior to cementing as well as the design and execution of the cement job. Both were critical to successfully completing the job.
Reciprocating Cement Slurries After Placement by Applying Pressure Pulses in the Annulus
Authors: Haberman J. P. , Wolhart S. L. 
Published: December 2007

Abstract
This is a report on progress to reciprocate or vibrate cement slurries deep in wells, after placement, with the objective to prevent gas migration and to improve cement bond logs. Pulses of relatively low pressure (circa 100 psi) compressed air or water were injected into the annulus at the surface (Figure 1).
This imparted motion to the cement particles in the slurry in two ways: A fast pressure pulse traveled through the slurry at the speed of sound andA slower reciprocating motion resulted from the compressibility of the fluid.
The results of full-scale tests in wells are reported and discussed below.
Slim Hole Exploration: One Year Experience in Romania
Authors: Groenevelt P. , Brown D. , Keenan T. , Calis H. , Kerbart Y. , Fanuel P. , Lamine E. 
Published: December 2007

Abstract
FORASLIM 1 is an integrated Drilling and Coring system dedicated to the construction of wells with small diameter to depths of 3500m. The objective is to provide a high cost reduction of exploration drilling in remote onshore areas with the following requirements: Environmental impact minimisationDrilling EfficiencyDrilling safety(No reduction in well control and safety standards)Complete Geological Evaluation
In order to reach these objectives a fit for purpose drilling system has been developed (ref. 1). The Slim Hole rig FORASLIM 1 has been commissioned in April 1994. The first drilling campaign was completed by ELF Gabon and is related in reference 2.
The present paper relates the experience acquired with Shell during the drilling of three wells in Romania under an integrated services contract managed by the drilling contractor Forasol. This experience concerns the drilling and coring processes, and the quality of the geological evaluation obtained.
Predicting Microporous Low-Permeability Facies using Sonic and Nuclear Porosity Log in a Middle-East Carbonate Reservoir, Berri, Saudi Arabia
Authors: AlShammery Matter J. , Frignet B. G. 
Published: December 2007

Abstract
The Berri Hadriya limestone is a mature oil reservoir which has been produced for more than two decades. No gas cap is present. The oil sweep is assisted by flank water injectors. The lack of a straightforward porosity-permeability relation has been observed from core analysis. Extensive thin-section studies have shown that the presence of microporosity was the root cause of low-permeability/high-porosity zones. Today, 27 cored wells have been analyzed and revealed the presence of microporosity zones which severely affect reservoir performance. Until recently, microporosity has not been detected by conventional log analysis, and required costly and time-consuming core analysis.
Intuitively, the sonic responds primarily to porosity variation and also to factors such as lithology, fluid and texture. Since Hadriya formation has uniform lithology, and fluid, it is ideal for understanding the sonic-log response relative to only porosity and textural variations.
Sonic logs have been run in all cored wells in the field, but failed to detect microporosity on their own. However, by comparing porosities derived from sonic, neutron, and density logs, it was noticed that in zones of microporosity the sonic-derived porosity was always the highest among the 3 readings. This observation was confirmed in all Hadriya cored wells. A simple algorithm was then designed to flag microporous facies by comparing all three logs. A 90% agreement was obtained between log-derived microporosity detection and core results. The technique was later applied to 11 uncored wells, and the microporosity was re-mapped across the field. The new map better matches an already established flood-front position, therefore boosting our confidence in our prediction methodology.
An explanation relating the Hadriya empirical observations to the framework of the Biot-Gassmann sonic theory is given here. It may encourage future use of sonic logs in studying more carbonate reservoirs worldwide.
Performance Review - In-Situ Combustion Project, West Casa Blanca Field, Duval County, Texas
Authors: Eskew James O. 
Published: December 2007

Abstract
The West Casa Blanca Field in-situ combustion project was initiated in February, 1967 with air injection into the Cole reservoir. The field, which is located near Freer, Texas, contained 16 pumping oil wells with an average production of 62 barrels of oil per day prior to ignition. Primary recovery from the 1,030' reservoir had been 1.1 million barrels of oil, or 28 percent of the original oil in place.
By the end of May, 1967 production had increased to 160 BOPD with air injection of 1,500 Mcf per day. A burn front was formed as evidenced by the appearance of carbon dioxide gases in the producing wells. Production continued to increase with the Production continued to increase with the drilling of an offset well to the air injector and peaked at 346 BOPD during December, 1967. In October, 1969 the project was expanded with the addition of a second air compressor and air injection well. December, 1971 production averaged 151 BOPD. There have been production averaged 151 BOPD. There have been 371,000 barrels of oil produced since project start-up and 4,500 MMcf of air have been injected into the reservoir. The burned volume is calculated to be approximately 400 acre-feet of the reservoir.
only minimum data has been taken during the past five years of the project: well tests, air injection volumes, and gas analysis. This historical data is presented in this paper.
Corrosion Problems in Below Grade Wellhead Equipment and Surface Casings
Authors: Farooqui M.A.S.Z. , Bitar G.E. 
Published: December 2007

Abstract
Inspection of the below grade well head equipment has shown corrosion damage to the buried landing base, casing spools and surface casing, especially in water injection and supply wells in onshore fields in Saudi Arabia. This paper describes the problem, examines possible reasons for the occurrence of corrosion and then discusses procedures and standards that have been developed to regularly inspect all wells, perform the required repair work in a safe and cost-effective manner and provide durable protection with field-applied corrosion resistant coating on all buried equipment.

Introduction
Occurrence of corrosion damage in the buried well head equipment and surface casing immediately below the landing base has been a concern in the onshore fields in Saudi Arabia. Initial random inspections of the below grade wellhead equipment in the mid-eighties showed corrosion damage to the buried landing base, casing spools and surface casing. The damage was occurring in spite of an apparently successful cathodic protection program that has reduced the number of casing leaks due to external corrosion damage.
The possible causes of the corrosion damage are: leakage of water from surface piping and wellhead valves during various operations on water related wells, presence of highly saline and corrosive water close to surface in "subkha" terrain, and, impediments to effective cathodic protection at shallow depths.
In view of the safety and environmental hazards associated with possible shallow leaks from corroded casing or failure of wellhead equipment, a number of steps have been taken to control the damage. These include regular inspection and repairs at regular intervals, protection with field-applied corrosion resistant coatings and a requirement to coat all new wells immediately after the rig release.
Regular inspection and protection of the below grade wellhead equipment has successfully reduced potential hazards associated with casing failures at shallow depths. Repair and renovation costs have been effectively reduced by establishing guidelines for safe acceptable thickness limits and by adopting rigless repair procedures.

Problem Description
Typical landing base and surface casing equipment for onshore wells is depicted in Figure-1. The 13-3/8" casing is either welded or screwed on to the 13-3/8"x13-5/8" landing base. The 18-5/8" conductor pipe is cemented at a distance ranging from a few inches to 2–3 feet below the landing base.
A typical landing base inspection operation involves excavating the cellar to below the landing base to expose three to six feet of the surface casing or until hard cement is encountered below the landing base, which ever is earlier. The exposed section is sand blasted and then inspected for evidence of corrosion. The data from such inspections for the last six years (1991 through 1996) is presented in Table-1, while Figures 2 through 4 illustrate some cases of severe corrosion damage on the landing base and surface casing on oil as well as water wells.
P. 283^
Encapsulated Scale Inhibitor Treatment
Authors: Al-Thuwaini J.S. , Burr B.J. 
Published: December 2007

Abstract
Scale formation and deposition (CaCO3) in production facilities is a problem encountered in the Ghawar Field in Saudi Arabia. The scale deposition causes production loss and safety hazards. Downhole scale inhibitor squeeze treatments have proven successful in controlling this scale accumulation. However, weak producers (low oil rate and high water cut wells) could not be squeezed due to the difficulty anticipated in re-starting production from these wells because of the high volume of water normally needed to squeeze the inhibitor into the formation. Starting in 1994, an alternative method (the encapsulated inhibitor treatment) was tried for selected weak wells.
This paper presents the design of the encapsulated inhibitor treatment, treatment procedure, a field case history with scale inspection results, economical analysis of this treatment versus the regular downhole treatment and the future plans. To-date, more than ten treatments have been performed in Saudi Arabia. Regular visual inspection of selected wells revealed no scale accumulation up to 24 months after the treatment. Current plans are to treat more wells for further evaluation.

Introduction
Calcium carbonate CaCO3 scale is the most common scale encountered in the Ghawar field production wells. Its deposition in surface and subsurface equipment causes loss in oil production and major operational problems. The scale control program was started in the Ghawar Field in 1986, and since then, conventional scale inhibitor squeeze treatments have been successful in controlling scale accumulations. Saudi Aramco field experience has shown that weak oil producers, especially high water cut wells (WC &gt;70%), when treated using a conventional scale inhibitor squeeze, require several reviving attempts before the wells can be put back on production and in some cases the wells might remain dead. This is mainly due to the hydrostatic head created by the large treatment fluid volumes normally pumped during a conventional treatment where the inhibitor is squeezed into the formation to a predetermined radius.
In 1994, a new scale inhibitor treatment "Encapsulated Inhibitor Treatment" was introduced to Saudi Aramco. The main advantage of this treatment is the placement of the treatment fluids in the rathole rather than squeezing it into the formation. Therefore, the encapsulated scale inhibitor treatment is suitable for the weak wet oil producers with high water cut. To-date, more than ten wells in the Ghawar Field and an offshore field have been treated with the encapsulated inhibitor, without any difficulty in bringing the wells back on production. Some of these wells are being closely monitored for rescaling by performing regular visual inspections. To date none of these treated wells have shown scale redeposition after up to two years following the treatment of the first well.
P. 295^
Drilling Contracts and Alliances: The Pendulum Swings
Authors: Gooch Stephen G. 
Published: December 2007

Abstract
As the attached graphs (Figures 1, 2, and 3) illustrate, utilization of offshore rigs has increased to levels not seen since the early 1980's creating supply shortages in many markets. This tight market condition is expected to continue for some time as demand is not anticipated to abate and the supply will be relatively static. While rates are approaching levels high enough to encourage new builds, as yet a spate of new construction has not ensued. Even if new construction occurs, it will take another two or three years for deliveiy of these new rigs. How has and will this tight market condition affect drilling contracts and alliances?
DRILLING CONTRACTS
In general, operators have used a favorable supply/demand rig ratio during the past 15 years to reshape drilling contracts in their favor. The current tight market has reversed this trend, at least in part, and is expected to continue to do so. The purpose of this presentation is not to seek out perceived inequities in drilling contracts, but to focus on certain issues which will be impacted by the tight market. The following is a discussion of some of these issues.
Extension Options
I have chosen to address the issue of extension options first since options have become a major impediment in predicting rig availability and securing future jobs both for the drilling contractors and rig-seeking operators.
Drill Fast, Safe and Friendly with Incentive Contracts
Authors: Reiley Richard H. 
Published: December 2007

Abstract
Abu Dhabi Company for Onshore Oil Operations (ADCO) recently initialed an incentive contract to encourage drilling wells quicker, safer and in an environmentally friendly manner, Not content just to drill fast, safe and friendly, the Drilling Division made the incentive award contingent upon delivery of high quality wells free of defects. This paper describes the structure and implementation of effective incentive contracts.