bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Pressure-While-Drilling Measurements To Solve Extended-Reach Drilling Problems on Alaska's North Slope
Authors: Mallary C. R. , Varco Martin , Quinn D'Arcy 
Published: December 2007

Abstract
Extended-reach drilling (ERD) is playing an important role in the economic development of Alaska's North Slope oil reserves. For some ERD wells, careful well planning and existing drilling practices are sufficient to avoid problems such as wellbore instability, lost circulation and stuck pipe. However, recent Alaskan experience has shown that as well step-outs increase, some operational practices developed on conventional wells are inadequate to successfully deliver cost effective ERD wells. On these wells, careful planning alone cannot always prevent costly drilling problems.
The ability to analyze down hole annular pressures with pressure while drilling (PWD) data has proved invaluable to the drilling engineer. The value of this information is not fully realized, however, until it is put in the hands of the man on the rig who can act on it in real time. This paper examines the impact PWD measurements have made in recent Alaska ERD wells and focuses on both planning and operational uses. Field data are presented from problem and non-problem wells to underscore successful and unsuccessful operational practices. The importance of rig-site training in equivalent circulating density (ECD) management and linkage to drilling, circulating and tripping practices is developed.
The Long-Term Effect of Cyclic Steam on Gravel-Packed Liners
Authors: Hollman G. F. , Tague J. R. 
Published: December 2007

Abstract
Cyclic steam injection is commonly used to improve production in heavy oil fields. The process consists of injecting high temperature steam down the wellbore, and after a soaking period, returning the well to production. In general, high temperature steam improves productivity by decreasing oil viscosity and increasing gravity drainage. However, the same high temperature steam used to improve performance can alter the mineralogy of the gravel-pack materials and near wellbore formation. Recently, a study examining the impact of cyclic steam on the productivity of gravel-pack completions was completed in the West Coalinga field. The study found cyclic steam to be extremely detrimental to the long-term performance of gravel-packed slotted liners due to dissolution and reprecipitation of various minerals found in the gravel-pack materials and localized formation. The conclusions were based on analysis of production profiles of gravel-packed wells undergoing cyclic steam injection and the actual physical inspection of gravel-packed liners cut and pulled from producing wells. Given the results of this study, caution is recommended when considering cyclic steam operations on gravel-packed liners.
Multiphase-Flow Measurement System of High-GOR Applications
Authors: Cellos Harry , Wee Arnstein 
Published: December 2007

Abstract
This paper presents the findings from an installation at Prudhoe Bay which was started up on October 22, 1998. This system consists of a MFI multiphase flow meter, a partial separation separator and a coriolis effect flow meter. The separator is used to widen the operating envelope of the multiphase meter. The control of the separator, data acquisition and final calculations are done by the MFI multiphase flow meter.
Since the system has a very wide operating envelope it can be used on groups of wells with widely divergent flow rates. This particular system is designed for accurate flow measurements with GOR's up to 80 000 scf/bbl and it can handle liquid flow rates in the range 100 – 15 000 bbl/d. The accuracy of the oil flowrate is typical within 5% and the gas flow rate is measured within 1-2 %.
The key element of the system is the MFI multiphase flow meter which is used to measure the multiphase flow in the "liquid leg" of the compact separator. Unlike most well test systems, the measurements of the liquid line are not adversely affected by gas carry under. In fact, it works best with gas flowing in the liquid line.
Operation and control of the system is greatly simplified by the fact that the primary goal of the separator is to remove the liquid from the gas.
The separator is designed to remove down to 5 ppm over the full range of flow rates. The excitation voltage of the coriolis meter is used to detect carryover down to 2-3 ppm. This variable is also used in the control logic and changes the vapor leg flow rate to eliminate carryover.
Optimizing Solvent Allocation in the Prudhoe Bay Miscible Gas Project
Authors: Weaver J. W. , Uldrich D. O. 
Published: December 2007

Abstract
This paper documents the solvent allocation modifications implemented within the Prudhoe Bay Miscible Gas Project (PBMGP) in 1998. These modifications are leading to a more efficient use of the limited miscible injectant (MI) supply by the water alternating gas (WAG) flood.
In 1991, a methodology was implemented in the PBMGP that allocated MI to all of the patterns via a tiered WAG ratio system. The goal was to optimize the use of available MI while controlling the pace of project expansion. Today, the PBMGP is approaching full expansion and currently consists of 149 patterns. The WAG flood now encompasses patterns with a wide range of EOR maturity, expected performance, and operational viability.
Simulation and theoretical analysis indicate that a tiered WAG ratio approach for solvent allocation is no longer optimal. A better method of allocating solvent is a binary system. This involves ranking all patterns in order of efficiency. Each pattern's MI demand is determined by applying a WAG ratio of 1.0 to its current throughput rate. Each pattern is then allocated MI according to its ranking until the MI supply is exhausted. Any remaining patterns are suspended until the next ranking exercise, or until more solvent becomes available.
By design, the binary allocation method redirects MI to the most efficient patterns at the expense of less efficient patterns. To determine each pattern's efficiency, a detailed analysis of field performance data was conducted. This analysis uncovered some patterns that were using MI much less efficiently than others. A number of these performed as if they were immature (implying high efficiency), and otherwise would have been ranked favorably. In reality, they were inefficient due to cement channels, out of zone injection, or poor correlation between injector and producer. These patterns have been suspended from MI injection pending repair.
Implementation of the binary allocation method at Prudhoe Bay is predicted to increase the instantaneous mobilized EOR oil rate between 5,000 and 15,000 stbo/D. The ultimate EOR recovery will increase by 10 to 20 million stb, or 2 – 4% of the original EOR estimate.
A Conceptual Model for Reservoirs Producing from the Monterey Fields, Offshore California
Authors: Ershaghi Iraj , Voskanian Armen 
Published: December 2007

Abstract
Monterey Formation is one of the most productive petroleum-bearing formations in California with substantial proven petroleum reserves both onshore and offshore. A key question in the study of the Monterey Formation is the role of the matrix in terms of its storage of hydrocarbons and its potential contribution to the total ultimate recovery. This issue itself affects the selection of a conceptual model for reservoir studies, resource management, and recovery optimization.
We conducted a study of petrophysical information and performance data from a number of offshore Monterey fields and conditioned our observations with other evidence from published geological studies. All indications are that the most prolific members of the Monterey Formation offshore contributing to well productivity are the brecciated quartz chert intervals (tiger striped chert) with substantial fracture permeability and fracture capacity. The geological processes leading to the formation of the quartz member, geological history of the chert intervals, and study of outcrops indicate that tight chert sections are not serving as pressure support for the fracture as originally thought. As such, the contribution of matrix to recoverable reserves is considered trivial. An interpretative study of the database confirms the existence of a massive network of microfractures communicating with major fractures. Storage capacity of microfractures is a component of the overall recoverable reserves. We have observed similar signals in analysis of core data, well logs, and pressure transient tests data, which confirms our position on this matter.
Diagnostic plots for pressure-time relationship for highly brecciated intervals resemble that of hydraulic fractures intersecting wells. Dual porosity responses observed in certain cases are attributed to the role of microfractures supporting the major fractures.
Drive mechanisms in the offshore Monterey fields are primarily aquifer support and solution gas drive. Communication among wells through the fractures and the aquifer stabilization is seen from interference tests and static pressure measurements.
Water production in certain wells can be excessive because of rapid movement of the oil-water contact (OWC) within the highly permeable fractured intervals.
A bundle of straws draining a tank is proposed as a conceptual model for effective description of the Monterey fields. In this type of a system, for estimating cumulative water influx within the drainage area of individual wells, we have used the X-Plot technique. This methodology allows the application of tank type material balance for aquifer influx calculation.
Innovative Production Enhancement Interventions Through Existing Wellbores
Authors: Hatzignatiou D. G. , Olsen T. N. 
Published: December 2007

Abstract
In the youthful development stages of many hydrocarbon-bearing basins, oil production is prolific, and the primary capital expenditures are primarily for surface facilities and infrastructure. Drilling costs are relatively small by comparison and payback times relatively short. In addition, in offshore environments drilling slots are often limited and at a premium. Therefore, sub par producing intervals are quickly abandoned and sidetracted to make room for new drilling targets with higher oil production potential. Much of this throw away and re-drilling culture still lingers today especially in the offshore industry. However, as the targets become smaller and less prolific, re-drilling may not always be justified as the primary production enhancement solution.
This work presents several production enhancement interventions that can be applied to existing wells to complement re-drilling efforts in a reservoir optimization program. More specifically, results presented address pro-and up-grading marine sequence type of reservoir structures where oil recovery from high mobility layers is usually very efficient, but production rates from the low mobility layers are less than optimum to sometimes minimal. Several industry techniques utilized to date are focused primarily on water shut-off methods at the producing wells, but not much effort is directed in addressing effective means of improving oil recoveries from the remaining less prolific layers. Results presented in this paper provide a variety of such interventions ranging from coiled tubing, hydraulic fracturing, selective zonal isolation-stimulation, sidetracking, etc. which can be applied depending on a given well/reservoir scenario to improve oil recoveries from poorly swept zones and via existing wellbores.
Determination of Production Operation Methods in Pubei Oil Field
Authors: Yang Dao-yong , Zhang Qi , Fan Ling , Bao Bing-sheng , Feng Guo-qiang , Liu Hong-ting 
Published: December 2007

Abstract
As water-alternating-gas (WAG) miscible flooding is the best method to enhance oil recovery for hydrocarbon reservoirs, recently there has been an increasing interest in the WAG processes. In the recent years some reservoirs suitable for miscible flooding have been discovered in the western part of China. The first WAG miscible flooding project, Pubei oil field in Xinjiang, was put into production and scheduled to initially inject miscible gas at the early development stage. One objective of this work is to describe the process of making the optimal field development strategies in this field by integrated technology.
Also presented are theoretical models for comprehensively evaluating and decision-making the oil well production operation methods. These models have been successively applied to thirty reservoirs or fault blocks in China. With consideration of the specialty of the WAG process, the models were developed by incorporating reservoir geologic research, reservoir engineering scheme, reservoir numeric simulation, production performance and surface facility performance. Meanwhile, a novel approach was introduced into the modeling process so that we can simulate the future production performance of oil producers under different conditions in the Pubei oil field.
It is shown that oil producers can maintain stable flowing and there still is potential for the reservoir pressure maintenance, and that gas lift, plunger lift and sucker-rod pumping can be efficient artificial lifting methods under different conditions.
Using New Technology To Overcome Pumping Problems in Horizontal Wells
Authors: Evans B. L. , Muth G. M. 
Published: December 2007

Abstract
Increasingly, horizontal wells are being used in the development of oil fields. The benefits have been shown to outweigh the additional costs in many fields. As could be expected, horizontal wells are experiencing the usual pumping problems (such as sanding) as those seen in vertical wells. In addition, deviated holes can cause additional rod and tubing wear and increased loads. The higher costs of horizontal wells and higher oil production rates create more urgency that the problems be overcome as quickly and economically as possible. The use of a downhole conversion kit allows the modification of the pumping system to a dual string system (a "power string" and a "production string"). This new system has been shown to be very effective in overcoming or mitigating the pumping problems of horizontal wells. The conversion kit can be used with insert, tubing or PCP pumps. In addition, the downhole assembly can allow the running of temperature and other surveys without the removal of any downhole equipment. This feature is especially helpful in steam injection projects.
Formation Damage Associated with Water-Based Drilling Fluids and Emulsified Acid Study
Authors: Lynn J.D. , Nasr-El-Din H.A. 
Published: December 2007

Abstract
Water-based fluids are used for drilling most of vertical and horizontal wells in carbonate reservoirs in Saudi Arabia. Even in moderate and lower permeability formations, drilling solids can invade the formation and cause fines plugging. An XC-polymer based drilling fluid, containing sized calcium carbonate particles (marble), is used to limit the amount of fluids lost to the formation during the drilling operations. However, near wellbore damage was evident from field tests conducted on several vertical wells. High skin factors (+2 to +4) following drilling indicated severe well damage and decreased production potential. The only solutions are drilling additional wells to increase production capacity, or stimulation of existing damaged wells. A stimulation procedure was needed to mitigate the problem.
Traditional stimulation efforts in carbonate reservoirs are conducted using regular HCl acid. Rock mechanical studies have indicated wellbore stability after drilling, and rock strength are concerns in the subject formations. It was suspected that an attempt at normal HCl acid matrix stimulation would result in surface washout and enlargement of the wellbore. This is especially true in low permeability (less than 30 mD), fine grain carbonates. This could exacerbate borehole stability problems.
Emulsified acids have been shown to induce deep wormholes in carbonates. These wormholes will serve the same function as perforations to by-pass the drilling damage, yet maintain the integrity of the formation. An emulsified 15 wt. percent HCl - diesel mixture (at 70:30 volume ratio) was evaluated as a portion of an ongoing study of the effects of acid stimulation in carbonate reservoirs.
Currently, there are few accurate methods of laboratory evaluation of this type of stimulation fluid, and scale up-factors are nebulous at best. Traditional tables for matrix type stimulation are inaccurate, and result in excessive acid volumes. Acidizing with large acid volumes is not recommended because of the weak nature of the rock in some fields.
This paper demonstrates a new laboratory core test procedure and provides a novel interpretation of scale-up equations developed for the study. The resulting laboratory data are compared to field results, and show:
1. The test procedure accurately simulates the damaged seen in the formation.
2. The acid can effectively stimulate the formation, while preserving the formation integrity.
3. The acid penetration and “worm-hole wander” can be controlled by monitoring acid injection rate and volume.
4. The scale-up volume equations to be accurate for emulsified acid treatments.
Gravel-pack damage removal in horizontal and vertical wells
Authors: Kotlar H. K. , Thomas R. , Ziauddin M. , Brydon H. , Karlstad S. 
Published: December 2007

Abstract
Gravel-packs can be damaged by a variety of mechanisms which include scale formation, fines migration, paraffin and asphaltene deposition resulting in a damage skin of 10-300. Frequently damage removal treatments do not remove this damage completely from all the producing zones, resulting in a short treatment life and/or inadequate production. This can be attributed to poor diversion and/or improper damage characterization. This paper focuses on several aspects of improved damage removal in gravel-packed wells. A methodology to assist in the proper identification of the damage mechanism and the design process for more effective treatments is presented. An integrated approach using an overall systems analysis coupled with log, water analysis and numerical simulations of the gravel-pack/matrix damage removal is recommended.
A numerical model to simulate acid treatments of gravelpacked well is presented and used to evaluate several treatments performed on wells from the Gullfaks field in the North Sea. Results indicated greater than 75% of the damage is in the gravel pack. The model incorporates a detailed wellbore model integrated with a reservoir mode for simulation of acidizing treatments in horizontal and vertical gravel-packed wells. An algorithm for quantifying the damage in the gravelpack is discussed in detail. Various diversion techniques and fluid formulations are evaluated using the simulator and compared to field results with emphasis on pre and posttreatment production logs.
The results of this study helped us establish guidelines for identifying the damage mechanism and in designing optimal treatments for matrix stimulation of gravel-packed wells.
Candidate and Chemical Selection Rules for Water Shutoff Polymer Treatments
Authors: Mennella Aniello , Chiappa Luisa , Lockhart Thomas P. , Burrafato Giovanni 
Published: December 2007

Abstract
Water shutoff treatments with polymers that selectively reduce the water permeability can be effective to reduce water production from hydrocarbon wells that cannot be treated with conventional approaches. In this paper we present an analysis that starts from the principal operative questions and defines the main physical-chemical issues to be understood in order to develop a reliable technology. These issues are discussed by showing results from a number of experimental and simulation studies conducted in our laboratories with the goal to link the understanding of basic mechanisms to the development of operational rules. This work shows the elaboration of understanding-based rules for candidate and chemical selection to be an effective strategy for the application of this technology in the field.
Investigation of Proppant-Pack Formation Interface and Relationship to Particulate Invasion
Authors: Weaver Jim , Blauch Matt , Parker Mark , Todd Brad 
Published: December 2007

Abstract
Many wells completed in soft, poorly consolidated formations tend to underperform relative to the reservoir's production potential. Steep production declines are also indicative of problems with the reservoir. These problems are often attributed to poor drilling and completion practices. Formation-incompatible fluids can be lost to the formation, resulting in significant nearwell permeability loss. Advances in soft-rock stimulation technology have made frac-packing the preferred method for bypassing damaged regions within the formation and for optimizing access to productive zones. Because many soft formations produce fines that can invade the proppant pack and lower productivity, choosing the optimal proppant size for such operations is paramount to overall production-enhancement success.
Numerous studies describe the optimization of proppant size as means of minimizing fines invasion and maximizing pack conductivity. This paper examines other mechanisms that affect pack conductivity and the prevention of fines invasion and migration. The results of this study provide a greater understanding of proppant-pack damage mechanisms and present evidence that proppant coated with chemical agents that make the proppant surfaces "tacky" can significantly improve fracture conductivity.
Microscopic observations of the proppant-pack/formation interface were performed with a dynamic flow model. Images taken from this model indicate that several parameters, such as particle surface charge, wettability, and proppant tackiness, greatly influence fines migration into a proppant pack, regardless of the proppant sizing criteria used. API conductivity measurements performed with realistic pressures, closure stresses, and flow rates were used to confirm micromodel observations.
This procedure provided a quantitative measure of the effects of size criteria and proppant tackiness on fracture conductivity. Fines invasion beyond the proppant-pack/formation interface was determined through postmeasurement microscopic examinations.
The effect of proppant tackifiers on the proppant-pack/ formation interface was also examined, resulting in significant changes in proppant-sizing criteria for frac-packing operations. These findings should have a significant impact on future frac-pack designs.
Enhancing Liquid Lift From Low Pressure Gas Reservoirs
Authors: Yamamoto Hiro , Christiansen Richard L. 
Published: December 2007

Abstract
Liquid loading in low production gas wells is a nuisance for production engineers in the natural gas industry. It is essential to maintain gas wells free of liquid; otherwise, the production will be severely reduced by backpressure of the accumulated liquids, and by reduced gas relative permeability in the surrounding formation.
The most fundamental solution for the liquid loading problem is to select tubing diameter for the well such that the natural energy in the reservoir will give a gas velocity sufficient to lift liquids from the sand face of the reservoir to the surface. Unfortunately, the optimum diameter varies for different periods in the life of a well.
Here, a new approach to the liquid loading problem is reported. By introducing restrictions, such as orifices, inside the tubing to alter flow mechanisms, liquid may be lifted by gas flow rates below the conventionally accepted critical rate. Extensive laboratory experiments with a 40-foot-tall flow loop with 1.5-inch-inside-diameter tubing were conducted to test the effect of five different designs of restrictions. In these experiments, the effects of gas flow rate, of restriction design, of flow loop inclination, and of design of the outlet at the top of the loop were considered. The experiments proved that the restrictions alter two-phase flow behavior and improve liquid lifting rate in the flow loop.