bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Best Hydraulic Fracturing Practices in the Golden Trend Fields of Oklahoma
Authors: Mohaghegh S. D. , Gaskari R. , Popa A. , Salehi I. , Ameri S. 
Published: December 2007

Abstract
In the past decades several hundred stimulation procedures have been performed in the Golden Trend fields of Oklahoma. The outcome of these stimulation jobs have not been the same for all wells. The effectiveness of the stimulation is a function of several factors including reservoir quality, completion and stimulation techniques. Completion and stimulation techniques can be further itemized as completion type such as open hole versus cased hole, type and amount of fluids and proppant and the rate at which they are pumped into the formation.
This project was supported by DOE and GTI in connection with the DOE's Preferred Upstream Management Practices (PUMP) project. The project was implemented in three fields in the Golden Trend in Oklahoma. Detailed production and completion data analyses revealed that the most influential controllable parameter effecting the production rate and ultimate recovery was fracture stimulation, and as such, the bulk of efforts were focused on determination of optimized hydraulic fracturing procedure. Detail stimulation data from more than 230 wells in the Golden Trend fields of Oklahoma operated by three independent operators were collected and analyzed using a new best practices analysis methodology.
The study was performed for gas and oil bearing formations. Among the findings of this comprehensive study were the best stimulation practices in carbonate formations that are primarily gas producing, and clastic formations, from which both oil and gas are produced. During his study authors were able to identify the best type of fluid, the most optimal injection rate and proppant concentration for both types of formations.
In this paper application of a new methodology that was used to perform the best practices analysis on the Golden Trend fields of Oklahoma is presented.
Experimental Investigation of Miscible Secondary Gas Injection
Authors: Kulkarni M. M. , Rao D. N. 
Published: December 2007

Abstract
Our earlier experimental work1 on tertiary mode gas injection indicated that the gas injection strategy, either continuous (CGI) or alternating with water (WAG), did not have a significant effect on recovery during immiscible gas injections. This paper examines the effect of gas injection strategy on recovery in miscible gas injection projects. Here we compare the effects of injection strategy (namely secondary and tertiary) on horizontal type, miscible continuous gas injection (CGI) and Water-Alternating-Gas (WAG) processes.
The secondary miscible corefloods demonstrated high oil recoveries in both CGI and WAG mode of injection, attributable to higher initial oil saturations and the high capillary numbers achieved due to miscibility. The flood performance was analyzed using the conventional recovery plots as well as the tertiary recovery factors, TRF, defined as the oil recovery per unit volume of gas injected. Comparison of the TRF plots for secondary and tertiary gas injections, clearly demonstrate the beneficial recovery effects of gas injection early in the life of the flood. On the other hand, the WAG floods demonstrated higher gas utilization factors than those in CGI under secondary mode of injection. The water shielding effect, responsible for delayed oil breakthroughs in tertiary floods, was observed to be minimal in the secondary WAG floods. This work reconfirms that the optimal injection strategy consists of a combination of CGI and WAG modes of injection, which appears to be independent of whether the gas injection is carried out as a secondary or tertiary process.
Can Large Domain of Uncertainty Be Reduced for Two One-Well Fault Blocks?
Authors: Macary S. , Ball B. , Baramawy M. 
Published: December 2007

Abstract
Two fault blocks, each containing one producing well, are part of a multiparty concession. Both blocks were tested by a major oil company in the mid 80's but proved to be non-commercial at that time and the wells were abandoned. Two further wells were drilled in early '01 and late '03 and have been on production since then. The short production history is common today for many companies pursuing marginal oil accumulations. Recent high oil prices have enabled viable production but the degree of uncertainty makes it difficult to diagnose reservoir performance and identify the best alternatives for future reservoir development.
The producing mechanism for the two fault blocks is believed to be depletion drive. However, high dip with some evidence of fracturing indicates possible improved recovery via gravity drainage. Material balance calculations utilizing limited production history, few pressure measurements and uncertain PVT data make it difficult to resolve OOIP, prevailing drive mechanisms, and ultimate recovery.
The BPP is also uncertain which consequently affects material balance.Accurate PVT data will give confidence in resolving the issue of whether a fault separating the two blocks is leaking.This fault is thought to be partially non-sealing as indicated by few uncertain pressure measurements, which complicate interpretations and decisions regarding further development.
The offshore location limits artificial lift or secondary recovery options. Production capacity is allotted from a shared facility and future decisions will require agreement among the involved parties. These concerns, in addition to considerable G & G unknowns regarding seismic definition of structure, facies variation, poroperm characteristics etc., generate a large domain of uncertainty. This is exacerbated by the interests and visions of the different partners and local regulations.
The best solution starts by an interdisciplinary team approach to enhance the understanding and potential impact of all available data through expert analysis and thoughtful integration. This results in more effective decisions regarding reservoir management and further development. PVT acquisition, multiphase metering, static modeling, reservoir simulation and infill drilling are some steps of an aggressive plan to develop this Concession.
Viscosity of Formation Water: Measurement, Prediction, and Reservoir Implications
Authors: Alboudwarej H. , Muhammad M. , Barrere C. , Archer R. , Hannan R. , Jones T. 
Published: December 2007

Abstract
Formation water is invariably produced with petroleum. An estimate of the dynamic viscosity of formation water as a function of pressure, temperature, salt content and preferably dissolved gas, is required for reservoir and petroleum production design and calculations. The extent of available experimental data on the viscosity of live formation water is very limited. In addition, most of the proposed brine viscosity correlations are based on the experimental data of NaCl solutions with no dissolved gas.
Several reconstituted formation water samples were tested in the present study. The total dissolved solids content of the water samples varied between 90,000 to 250,000 mg/L at a gas/liquid ratio of approximately 9.6 scf/stb. Viscosities were measured up to 14,000 psia and temperatures up to 200 °F using both capillary and electromagnetic viscometers calibrated with standard fluids for the interested range of pressure and temperature. Experimental results indicated that viscosity of formation water increases with increasing solids content and pressure as well as with decreasing temperature. The presence of dissolved gases decreased the viscosity of formation water; however, it was not significant. Experimental results were compared against water viscosities predicted by commonly used formation water viscosity correlations. The relative errors for some cases were as high as 200 %. Most correlations over-predicted the viscosities at higher pressures beyond 10,000 psia.
Comparison between reservoir simulation case studies for a base case and 30%-varied formation water viscosity case showed that both predicted oil and water production and water cut during the life of the producing well are significantly affected by the value of the formation water viscosity input.
C-Curve And Independent Oil-Rate And Oil-Cut Decline
Authors: Cunningham P. R. P. , Lecompte M. N. 
Published: December 2007

Abstract
Decline analysis is an important working tool, particularly for reserves evaluation in producing fields. However, its theoretical foundations are not fully understood and much work remains to be done to develop the theory and application of the method.
Based on practical experience of fitting decline curves to both field production and reservoir simulation results, the authors have identified two short-comings of conventional decline analysis, together with partial solutions to these problems. It is estimated that the two improvements together will lead to a significant improvement in the accuracy of decline analysis reserves evaluation.
The first problem is that of the limitations of hyperbolic curves and other alternatives to exponential decline. When field production or reservoir simulator results show non- exponential decline, the decline rate usually reduces in time (e.g. from 25% per annum to 15%, 10% etc), until levelling out and then continuing at a more-or-less constant rate (e.g. 5% per annum). In contrast, hyperbolic curves show decline rates than keep on reducing, eventually heading to a zero decline rate. In consequence, hyperbolic decline curves can give rise to unrealistically high ultimate recovery values. Instead of hyperbolic curves, an alternative generalisation of exponential decline is presented – the "C" or "cumulative" curve. These curves take a simple form; they include hyperbolic curves as a subset; and they allow the late-time decline rates to approach a non-zero asymptote.
The second problem is that there are cases where fitting a decline curve to the oil-cut curve gives a very unrealistic prediction of oil-rate, and vice-versa. A way of addressing the problem that has been found to be very successful is to fit independent decline curves to oil-cut and oil-rate and then use both simultaneously to predict how the gross-liquid production rate varies with time.
A Rapid, Rigsite-Deployable, Electrochemical Test for Evaluating the Membrane Potential of Shales
Authors: Al-Bazali T. M. , Zhang J. , Chenevert M. E. , Sharma M. M. 
Published: December 2007

Abstract
The membrane efficiency of shales is usually measured in the laboratory using pressure transmission techniques that can be very time consuming and require shale core samples that may not be available.These tests also require special high pressure equipment and cannot be conducted at the rig-site.
This paper presents a quick and relatively easy method for obtaining the membrane efficiency of shale cuttings (or cores) through electrochemical potential measurements. The electrochemical test measures the voltage drop across shales that are in contact with fluids of different salinities.The measured voltage drop is used to calculate the shale's ion selectivity, which reflects the shale's ability to restrict ion flow (membrane potential).Data are presented to show the influence of ion type and concentration, shale permeability and CEC on the ion selectivity.It was found that the shale membrane efficiency is well correlated with the membrane potential. The membrane potential is shown to be proportional to the ratio of the cation exchange capacity and permeability of shales.A higher cation exchange capacity to permeability (CEC/k) ratio correlates very well with higher ion selectivity. The rig site measured ion selectivity can be correlated with the spontaneous potential (SP) curves in the well.
The rapid determination of shale membrane efficiency using shale drill cuttings allows chemical interactions between shales and water-based fluids to be taken into account in wellbore stability calculations without the need for shale core samples.
Optimal Stimulation Treatments in Tight Gas Sands
Authors: Holditch S. A. , Tschirhart N. R. 
Published: December 2007

Abstract
Hydraulic fracture stimulation can improve the productivity of a well in a tight gas reservoir because a long conductive fracture transforms the flow path natural gas must take to enter the wellbore. Fig. 1a illustrates radial flow in the reservoir when no hydraulic fracture has been created. As can be seen, all of the gas must converge radially to a very small area called the wellbore. For a radial flow pattern, most of the pressure drop in the reservoir occurs near the wellbore. Figs. 1b and 1c show what the flow path of natural gas from the reservoir to the wellbore looks like after a successful fracture stimulation treatment. At early time, Fig. 1b, natural gas enters into the fracture from all points along the fracture in a linear fashion. The highly conductive fracture rapidly transports the gas to the wellbore. At late time, Fig. 1c, the gas in the reservoir is flowing towards an elliptical pressure sink and most of the gas enters near the tip of the fracture. Conventional wisdom in designing hydraulic fracture treatments for tight gas sands would suggest that successful stimulation of tight gas sands requires creating a long, conductive fracture filled with proppant opposite the pay zone interval. This is accomplished by pumping large volumes of proppant at high concentrations into the fracture using fluids that can transport and uniformly distribute proppant deeply into the fracture.
As fracture treatment technology has evolved, the trend has been to use more viscous fluids carrying higher concentrations of propping agents to create long, conductive fractures in tight gas sands. In the 1960's, slick water carrying very low concentrations of proppants (around 1 lb/gal) were used in many situations. These treatments were called water fracture treatments1. In the early 1970's, more viscous fluids were developed that were capable of carrying 5-6 lbs/gal of propping agents2. By 1980, delayed cross-linked polymer fluids were allowing the industry to pump treatments carrying as much as 10-12 lbs/gal of proppant3. The trend in the industry was to pump more proppant, to create the long, conductive fractures needed to optimize production from tight gas reservoirs.
Basic reservoir engineering calculations can be used to show that gas recovery and deliverability will be a function of propped fracture length and fracture conductivity in the reservoir interval. As the hydraulic fracture length and conductivity increase opposite the pay interval, the well will produce more gas at higher flow rates4.
Managing Deepwater Flow Assurance: Unique Riser Design Allows Dual Annuli Thermal Insulating Fluid Installation
Authors: Javora P. H. , Wang X. , Burman J. W. , Renfro K. D. , Weaver M. , Pearcy R. , Qu Q. 
Published: December 2007

Abstract
Flow assurance is one of the major considerations when designing a deepwater completion where undesired heat loss through the deepwater riser accelerates the formation of gas hydrates and the deposition of paraffin and asphaltene. In addition, any planned or unplanned shutdown of the well for various well operations for an extended period can result in critical heat loss, which then requires an extended warm-up time to restart the well. In some scenarios, restart of the well becomes impossible without assistance from chemical injection, unless of course, proper thermal insulation was implemented beforehand. Field applications of thermal insulating fluids have demonstrated significant reductions in heat loss by reducing conduction and minimizing thermal convection of the fluid. Such thermal insulating fluids have been applied with great success in many deepwater riser applications during the last several years.
For this major deepwater project in the GOM, "how to manage flow assurance" had been identified as key to success of the project from the very beginning of the planning phase. This paper details the selection criteria used in the riser insulation design for the project. Evaluation of several insulation options and combinations of options will be discussed, and the final selection of the preferred insulation method will be presented. The unique design of the deepwater riser enabled the operator to maximize the insulation efficiency by the proposed thermal insulation fluid and to meet the most stringent thermal insulation requirements of this project. Data from downhole temperature and pressure gauges and from the fiber optic DTS system will be presented.
Precommissioning to Startup: Getting Chemical Injection Right
Authors: Willmon J. G. , Edwards M. A. 
Published: December 2007

Abstract
The following paper will detail lessons learned from practical field experiences concerning the design, construction, and commissioning of a production chemical program for a green (new) field development. A competent program will require the interaction of various specialty products and services suppliers, including experts in flow assurance, modeling, fluid analysis and specialty chemicals. All are engaged in the early stages of the project and retained as resources throughout.
Areas addressed for the design and implementation of a chemical injection system include: Exploration: Collected bottom-hole samples are used for fluid characterization and risk assessment of any flow assurance issues. From this initial data, prevention and mitigation strategies, including but not limited to chemical inhibition, are developed. Chemical products can be developed and/or screened for effectiveness and applicability from this initial assessment. This includes performance screening, chemical-chemical compatibility testing, chemical-material compatibility testing, and product stability (which are particularly important for umbilical applications).Facility Design: Specifications for the processing system and equipment are detailed; materials of construction are screened for chemical and fluid compatibility, volume and deliverability requirements determined, and the chemical injection system are designed.Facility Construction: Monitoring and oversight throughout the construction process is performed to maintain the integrity of the initial design.Operational Strategies: Strategies will be developed addressing initial flow-back, start-up, steady state, and shut-in techniques.Logistic Strategies: Strategies will be developed addressing logistical concerns (product transfers and hand-overs).(Pre) Start-up commissioning and testing of equipment: Cleanliness and operability of the system is an absolute must. The chemical day tanks and injection lines are flushed to specification.
Chemical injection issues can be successfully managed in new (Deepwater) projects by: proper fluid characterization and risk assessment, field development strategy that includes design, specialty treating chemicals and operating plans, the involvement of specialists and specialty providers, and training and communication ensure safety and success.
Value of Information for Appraisal of Multiple Dependent Prospects
Authors: Kumar R. , Hara S. K. 
Published: December 2007

Abstract
Two common challenges in the appraisal of deeper prospects in deepwater are, the selection of the overall strategy -campaign or sequential, and justification of any individual activity in this high cost environment. Both require objective assessment of the Value of Information.
When dealing with multiple adjoining prospects, which not only have subsurface dependencies in their uncertainty characterization, but also dependent development concepts, the value of appraisal appears to be intuitively high. However, quantifying such VOI is extremely challenging since the different combinations of subsurface realizations and development scenarios propagate into millions of economic realizations. Furthermore, the time and effort needed to update the analysis for new information is nearly as great as for the first complete iteration.
Traditionally such a problem would be solved using three branches for volume uncertainty (Low, Mid, High) for each of the prospects; details are lost in the analysis that may result in the VOI being non-representative. This paper presents a methodology that samples the probability density function more exhaustively but does so very efficiently w.r.t calculation overhead. A two-pronged approach is adopted: Defining a nearly exhaustive range of the discrete combinations of subsurface volumes from different prospects, then "binning" these possibilities in volume to create a representation of the frequency distribution.Recursively pre-calculating the economic simulations for numerous combinations of bins of volumes for different development concepts / strategy
This methodology enables studying the problem in much greater detail and also decreases the turnaround time to update the expected economic value and VOI as new data is gathered and other insights are gained. The probability density function can be quickly updated when only the probabilities change while the realizations and scenarios remain unaffected.
This paper demonstrates the application of the above approach in evaluating appraisal VOI for a set of adjoining prospects in deepwater Gulf of Mexico that are both geologically dependent and share potential development synergies.
High-Tech Tools Improve Petroleum Industry Human Resource Management
Authors: Rueff S. , Thomas J. , Lee W. J. , Weatherford D. -J. 
Published: December 2007

Abstract
Career paths in the petroleum industry no longer follow the straight line from college graduation to the gold watch at retirement; in fact, job mobility has become an indicator of an employee's ability and ambition to compete. Furthermore, industry reorganizations over the last decade have led to a workforce that is scattered, aging, and nettled by shortages in key discipline skills that are likely to be filled by an increasingly international workforce. High-tech e-staffing systems offer today's mobile jobseekers access to worldwide oil and gas industry employment opportunities and offer employers tools that provide fast, efficient, economical access to international professional personnel.
Carter Creek Slimhole Well Design Enhances Development-Drilling Economics
Authors: Weatherl M. H. , Marshall J. 
Published: December 2007

Abstract
Starting in late 1997 a major development drilling campaign was undertaken by Chevron in the Carter Creek Field in Southwest Wyoming. The sour gas reservoirs at +/-15,000’ TVD were targeted to increase production and improve ultimate recovery in this mature area. Between 1997 and 2002 15 new wells were drilled and completed as a part of this effort at approximately $8 million per well. The formations in this part of the Rocky Mountains are characterized by complex geology, hard abrasive formations, plastic salt, and high concentrations of hydrogen sulfide gas (16%). Additionally, the field is located on environmentally sensitive federal lands. Directional drilling is generally necessary to reach the desired bottom hole locations from the available surface access routes.
Overall, the program was very successful, resulting in 5-8 BCF of incremental gas reserves per well. However, by late 2002, bottom hole pressure had declined to the point that the new wells were becoming marginally economic. Although a core area and major capital project for the operator, it became clear that the remaining reserves could no longer support the associated well construction cost. The viability of a large gas plant and more than 100 BCFG recoverable reserves were at stake.
During 2002 and early 2003 multi-discipline team work was undertaken to assess possible alternative well designs utilizing a variety of risk analysis tools. The result was a slim hole well design enabling the use of a smaller drilling rig and an overall savings which to date has approached $1 million per well. This paper details the evolution of a new well design which balances geological and production objectives with the increased risk related to a smaller hole size. At present, the new well design is being utilized at increasing depths with continued efficiency gains. The associated well construction cost savings have become instrumental in maximizing value from this important asset.