bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect Of Residual Oil On Deep-Bed Filtration Of Particles In Injection Water
Authors: Ali Mohammad A.J. , Currie Peter K. , Salman Mohammad J. 
Published: December 2007

Abstract
Production of hydrocarbons is usually accompanied by the production of water. This produced water consists of formation water and/or water that has previously been injected into the formation. As more oil is produced, the amount of produced water increases. Unfortunately, the produced water is not a saleable product, hence, an operator must find ways to handle relatively large amount of water in an environmentally-acceptable manner at the lowest cost. One way of managing this water is to re-inject it for disposal, pressure maintenance or enhanced oil recovery. An important and difficult task in the re-injection process is the prediction of the impact of water quality on well injectivity. This is mainly due to the poor understanding of the deposition mechanisms by which suspended solids and oil droplets present in the produced water are retained by the formation.
As part of a study on formation damage, different concentrations of hematite particles suspended in water were injected into sandstone core samples at residual saturation. The theories of deep bed filtration are evaluated. The effects of residual oil on the filtration coefficient λ and the formation damage factor β are examined. The presence of oil caused greater apparent damage (reduction of permeability). It was also observed that there is rather deeper invasion at residual oil saturation than at fully brine saturation,
Solid Expandable Tubulars Expedite Access to Untapped Reserves from Existing Offshore Facilities
Authors: Radtke Cameron , Rivenbark Mark 
Published: December 2007

Abstract
Historically, operators used solid expandable tubulars as contingencies to mitigate unexpected hole problems, minimize loss of hole size and to meet project objectives. However, some operators quickly realized that by incorporating this technology into their initial field development and workover plans, previously untapped reserves could be brought online.
An operator in India combined solid expandable tubulars with sidetracking operations to reach additional reserves with optimized hole size in several offshore wells. Sidetracking out of a milled window results in loss of hole size with consecutive casing strings bringing further reductions. In this common scenario, the operator could be faced with drilling the drain hole with slimhole tools that drastically reduce the flow area and limit logging and drilling equipment availability.
Planning the application of solid expandables through the milled window in these vertical wells allowed the operator to economically extract previously unswept reserves. With conventional technology they were faced with exiting out of the 9-5/8 in. casing and setting 7 in. and 4-1/2 in. liners to isolate problematic and depleted zones above the pay zone. The pay zone would be drilled using 3-3/4 in. slimhole tool strings that placed restrictions in the outflow of the reservoir and compromised the workover program economics.
This paper will discuss how the planned-in use of expandable tubulars enabled the operator to sidetrack and recomplete poor-producing vertical wells into horizontal wellbores. This approach allowed the operator to maintain optimum drain hole that resulted in a five-fold increase in daily oil production. The paper will describe the complimentary technologies used with the solid expandables and the lessons learned in the first two wells. The operator/contractor relationship will also be discussed regarding project management of multi-well workover programs for both offshore and onshore fields.
Development of an Optimized Formulation for Cleaning Water Injection Wells Drilled With Oil-Based Systems
Authors: Dalmazzone C. , Le Follotec A. , Audibert-Hayet A. , Twynam A. , Poitrenaud H. 
Published: December 2007

Abstract
It is widely known that formation damage during drilling and completions are of prime concern for production wells. Formation damage impacts in injector wells, however, have not received the same level of detail and understanding. Water injection wells are of major importance in hydrocarbon recovery. Water injection wells are often completed as open holes, therefore, mud cake clean-up and damage removal by production of formation fluids is often performed in order to maximise subsequent water injectivity. In some wells, however, this production phase can be prevented due to surface handling limitations or low reservoir pressure. In most cases, when a well cannot be backflowed for long periods, it is possible to bypass near wellbore damage by exceeding the fracture pressure, but this may strongly affect sweep efficiency and uniform injection. Consequently, it is often necessary to inject water immediately after drilling and completion i.e. no possible production phase. In this case, a complete well cleanup is required, including the removal of the majority of mud filter cake components in order to maximise water injectivity. The objective of the present study was to develop a completion fluid formulation, based on a previous breaker technology developed by IFP, that allows complete disruption of the oil based mud cake by coalescence of water droplets and dispersion/dissolution of solids which is also compatible with all drilling and production fluids. The experimental methodology used in this study included several steps: the screening of efficient water based additives for dispersing/dissolving solids, the formulation of water-in-oil emulsions with controlled delayed kinetics of breakage adapted to the planned completion program, the assessment of the formulation compatibility with production fluids and finally the validation of clean-up efficiency with dynamic core filtration tests with a significant injectivity enhancement.
Managing Formation Damage Risks from Scale-Inhibitor Squeeze Treatments in Deepwater, Subsea Fields in the Campos Basin
Authors: Bogaert Philip , Berredo Marcos C. , Toschi Celso , Bryson Bill , Jordan Myles M. , Frigo Dario M. , Afonso Macros 
Published: December 2007

Abstract
This paper describes field experience and lessons learned from bullhead deployed scale-control operations in a deepwater subsea development in the Campos Basin, Brazil; specifically, deploying such treatments from the FPSO host, along the production flowlines, into four low-watercut, horizontal subsea wells, completed with sand control.
The relatively small number of high-cost, highly productive wells, coupled with a very high barium-sulfate scaling tendency upon breakthrough of injection water, meant not only was effective downhole scale management critical to achieve high hydrocarbon recovery, but even wells at low water cuts were deemed to be at sufficient risk to require squeeze application.
Initial bullheaded scale treatments comprised mutual solvent preflush, a water-based mainflush, and diesel overflush;so-called "hybrid" treatments.As water production rates rose, so did the treatment volumes required.To improve the logistics of these treatments and to mitigate issues arising from poor injectivity of diesel in these wells, core studies were conducted to investigate the option of exchanging the overflush fluid from marine diesel to injection-quality seawater.This change also introduced the possibility of forming a gas-hydrates plug during shut-in, but this was managed using a thermodynamic hydrate inhibitor and by replacing the flowline contents to flashed crude during the shut-in period.The operational aspects and the response of the wells to the modified treatments will both be compared with those previously deployed, in particular, in terms of the injectivity of the wells during treatment and well clean-up rates and productivity afterwards.
The core studies also highlighted a formation-damage mechanism caused by incompatibility between mutual solvent and the produced oil, which required modification of the treatment.
New Mechanical and Damage Skin Factor Correlations for Hydraulically Fractured Wells
Authors: Mahdiyar H. , Jamiolahmady M. , Danesh A. 
Published: December 2007

Abstract
Hydraulic fracturing is one of the most common well stimulation techniques. Hence, considerable amount of efforts has been devoted to study their performance under different prevailing conditions. Description of hydraulically fractured wells using the existing commercial reservoir simulators requires the use of very fine grids, which is very cumbersome, costly and impractical.
In this work a two dimensional single-well mathematical simulator has been developed, which is based on finite-difference methods, and simulates linear Darcy flow in a hydraulic fractured well. Based on the results of our in-house simulator different correlations have been developed for calculation of fracture (Sf), face damage (SfD), and chocked damage (Sck) skin factors. These formulations benefit from relevant dimensionless numbers expressing the effect of geometry and those used to quantify the extent of damages occurred during fracturing operation. The results indicate that in-house Sf values are more accurate than those available in the literature. SfD, reflecting the reduction of the permeability of the rock close to the fracture, is more realistically captured here when damaged thickness is assumed to decrease linearly towards the tip of the fracture. This is more superior to the uniform thickness assumption made in the literature, which overestimates SfD. It is also shown the available analytical expression for calculation of Sck, which is a reflection of reduction of fracture permeability, overestimate Sck hence, a more realistic correlation has been developed for this purpose.
The skin correlations developed here enables the engineers to study the productivity of a fractured well using simple open-hole system. They can also be used for the optimum design of a hydraulic fracture system by minimizing flow resistance for a given fracture volume and fracture permeability. This can be achieved readily by conducting simple derivation of the mathematical expressions of skin formulations presented here.
Optimisation of Perforation Techniques for Deep, HP Stringer Wells Located in the South of Oman
Authors: Laws M. S. , Al-Riyami A. M. N. , Soek H. F. , Pettitt A. 
Published: December 2007

Abstract
The intra-salt carbonate stringers represent a new oil province located in the south of Oman.To date, over 60 wells have been drilled in and around these reservoirs that in general are high pressure, deep and sour.Fluids within the fields range from a retrograde gas condensate to light oil. The stringers are geologically heterogeneous and commonly have low permeability.They are being developed in a phased manner that will involve miscible gas injection.
This paper describes the strategy that was developed by Petroleum Development Oman to optimize perforation techniques.
Perforations were required to by-pass the drilling induced impaired zone to enable effective stimulation of the reservoir and enhanced inflow performance. It was planned to perforate under-balanced, to apply the highest perforation phasing, to leave minimum gun debris in hole and to pull guns to surface to verify charges had fired and that the reservoir was amenable to future reservoir management activities.
Simulations were carried out to predict penetration depths in the formation using newly developed in-house software and the results were compared with those from an industry-recognised package of a major Service Provider.
In addition, the performance of commercial shaped charge perforators in full bore Harweel core was evaluated under pseudo downhole conditions. A series of tests with agreed procedures were carried out to compare perforation performance in actual core compared to that from industry recognized API RP19B Section 1 tests in cement.
The paper will provide an assessment of the predictive capabilities of the software packages in light of these laboratory tests on Harweel core samples as well as a comparison of the actual perforation performance of the evaluated charges.
Economics of GTL Technology for Gas Utilization
Authors: Ogugbue Chinenye C. , Chukwu Godwin A. , Khataniar Santanu 
Published: December 2007

Abstract
The world's natural gas proven reserves show enormous clean burning energy resources that call for its effective and efficient utilization. These gas resources, exceeding 6000 trillion cubic feet (TCF), currently represent a significant proportion of the energy equivalence of proven oil reserves. With over sixty (60) percent of such gas reserves located too far from potential markets, there is need to evaluate the prospective economics of promising technologies for the monetization of these stranded gas reserves. The main focus of this paper is the economics of the chemical conversion of natural gas to synthetic liquid fuels, favored by recent advances in Fischer-Tropsch (F-T) synthesis techniques, welcomed shift-to-liquid fuel transportation operations, and increased demand for clean burning diesel fuels. The value of this emerging technology will be the ability to turn natural gas reserves, currently too remote from the market, into high-quality premium products that could be transported as liquid fuels.
The effect of capital expenditures (CAPEX), annual operating expenditures (OPEX), product price and various tax schemes on the rate of return (ROR), pay out time (POT) and the net present value (NPV) is investigated to access the economic viability of GTL plants. The range of CAPEX utilized is based on the production of one barrel of hydrocarbon liquid per day (BLPD) whereas the OPEX are expressed as percentages of CAPEX. Also, a construction period of three years is considered, while a 10% net-back on product sales is incorporated to account for the cost of natural gas feedstock. Monte-Carlo simulation is utilized to run sensitivity analysis, incorporating the probabilistic approach, to generate insightful scenarios on the project economics. The results (measures of profitability and their certainty bands) are analyzed and presented in tables, histograms and charts for a 100, 000 BLPD GTL plant.
Economic Decisionmaking and the Application of Nonparametric Prediction Models
Authors: Attanasi E. D. , Coburn T. C. , Freeman P. A. 
Published: December 2007

Abstract
Sustained increases in energy prices have focused attention on gas resources in low permeability shale or in coals that were previously considered economically marginal. Daily well deliverability is often relatively small, although the estimates of the total volumes of recoverable resources in these settings are large. Planning and development decisions for extraction of such resources must be area-wide because profitable extraction requires optimization of scale economies to minimize costs and reduce risk. For an individual firm the decision to enter such plays depends on reconnaissance level estimates of regional recoverable resources and on cost estimates to develop untested areas.
This paper shows how simple nonparametric local regression models, used to predict technically recoverable resources at untested sites, can be combined with economic models to compute regional scale cost functions. The context of the worked example is the Devonian Antrim shale gas play, Michigan Basin. One finding relates to selection of the resource prediction model to be used with economic models. Models which can best predict aggregate volume over larger areas (many hundreds of sites) may lose granularity in the distribution of predicted volumes at individual sites. This loss of detail affects the representation of economic cost functions and may affect economic decisions. Second, because some analysts consider unconventional resources to be ubiquitous, the selection and order of specific drilling sites may, in practice, be determined by extraneous factors. The paper also shows that when these simple prediction models are used to strategically order drilling prospects, the gain in gas volume over volumes associated with simple random site selection amounts to 15 to 20 percent. It also discusses why the observed benefit of updating predictions from results of new drilling, as opposed to following static predictions, is somewhat smaller.
Comparative Analysis of Damage Mechanisms in Fractured Gas Wells
Authors: Friedel Torsten , Mtchedlishvili George , Behr Aron , Voigt Hans-Dieter , Häfner Frieder 
Published: December 2007

Abstract
Productivity impairment in tight-gas formations is a typical phenomenon for fractured wells. Processes responsible for this behavior are related to the characteristics of the porous media, and are induced as a consequence of the fracturing process. Fracture damage has been discussed in the literature for decades. In almost all cases, effects were considered in isolation. This is often not appropriate since natural effects such as stress dependency, fracture closure, and non-Darcy flow are interdependent. The same applies for the cleanup process where the back production of the loadwater from the leakoff zones can be influenced by mechanical damage caused during the fracturing process, or by capillary forces and the gel residues of unbroken fracturing fluids within the fracture plane.
This study analyzed the most common damage mechanisms by means of both generic and real field data. The latter was taken from German Rotliegend gas wells, which were history-matched and used for the evaluation of their cleanup and longterm production behavior. The results obtained were used to rank the individual processes for their damage potential. In addition to a commercial model, a customized in-house simulator was required in order to capture the specific physics.
Results suggest that the consequences of processes independent of the reservoir conditions are not negligible when compared to the damage induced by the fracturing itself. In particular, in tight-gas, the stress dependency of the reservoir rock and fracture closure both tend to have a significant impact on the longterm productivity. Furthermore, inertial non-Darcy flow can cause much higher production impairment than, for example, hydraulic damage. It also shows that low permeability reservoirs are more affected by non-Darcy flow effects in both the fractures and the reservoir than is generally assumed.
Production Pofile of Wells Before and After Treatment Using Novel ThermoChemical Technique
Authors: Amin Remy Azrai M. , Halim Nor Hadhirah , Rosli Kamal Amri , Ali M. Izat , Winnie Ho Wei Nee , Mohamad M. Hafiz 
Published: December 2007

ABSTRACT
Most of PETRONAS fields in Malaysia have been producing for more than 20 years. At this advanced stage of depletion, reservoir driving forces are low. Organic deposition, particularly in the near-and-around well bore region and in production tubing, can further reduce the production of oil by restricting the flow passage from reservoir to wellbore. A study to address this issue with a view to rejuvenate the problem wells through laboratory analysis & pilot field implementation was conducted.
A unique thermo-chemical system has been developed as an effective tool for 1:- Removing the organic deposits near-and-around wellbore and production tubing, henceEnhancing the production from the treated wells.
The two components of the system are injected simultaneously into the wellbore through production tubing. Upon mixing, both components will produce heat and reaction products. The heat generated capable to melt and dislodge the organic deposits. While, the reaction products will act as an effective solvents and surfactants for dispersion of organic species.
The objective of this paper is to present the result of 4 wells treated by the thermo-chemical system. Well selection criteria based on production profile and well history is described. The implementation technique and a post treatment production gain are also highlighted.
Probabilistic Determination of Productivity Index for a Horizontal Well in a Heavy-Oil Reservoir
Authors: Lisboa E. A. , Castro M. R. 
Published: December 2007

Abstract
The objective of this study is to determine the minimal well length required to achieve a desired productivity index (PI). It considers the main uncertainties associated to fluids and reservoir properties (vertical and horizontal permeability, net oil thickness and oil viscosity). Monte Carlo analysis is used to consider possible combinations of these parameters and generate probabilistic results.
This study was developed for a heavy oil reservoir. Oil of 15°API or less and viscosities up to 150 cp are expected. The results obtained can be used in the planning phase. The reservoir properties are evaluated initially by a pilot well; afterwards they are estimated along the horizontal length. During the horizontal well drilling, this model can be easily updated. A theoretical model presented in JOSHI (1988) is used to calculate the horizontal well PI. It considers the influence of anisotropy in permeability.
This work is divided in two parts. Initially, a sensibility analysis is performed regarding each uncertainty parameter separately. This first stage is necessary to evaluate the most impacting parameters. The procedure was applied for several well lengths. In a second phase, Monte Carlo analysis is applied, considering simultaneously the uncertainties associated to these parameters. This analysis provided three levels for well PI: pessimistic, most probable and optimistic curves as a function of well length.
This methodology is flexible and, for this practical case, it was implemented through a spreadsheet that comprised the required probability density functions and the Monte Carlo analysis. It can be implemented with other development programs that suit the reservoir engineer. The results obtained can improve the estimates for the performance of the wells and can be used to design adequate horizontal wells for field development.