bluuebunny/crossref_metadata_2025_split huggingface dataset:
Underbalanced Drilling Borehole Stability Evaluation and Implementation in Depleted Reservoirs, San Joaquin Field, Eastern Venezuela
Authors: Azeemuddin M. , Maya D. , Guzman E. A. , Ong S. H. 
Published: December 2007

AbstractDrilling underbalanced is often expected to prevent formation damage, avoid lost circulation, and increase rate of penetration. However, it is also risky and may lead to borehole collapse due to lack of positive support provided by the borehole mud. Hence, its feasibility should be evaluated thoroughly through an accurate evaluation of in-situ stresses and a realistic estimation of formation rock mechanical properties. These two entities combined with the proposed borehole trajectory and mud weight design play an important role in avoiding borehole instability problems and achieving the field objectives.A study was conducted in San Joaquin field in Eastern Venezuela, to evaluate the feasibility of drilling underbalanced in highly depleted sands inter-layered with normally pressured shales. Data required for the study was obtained from five wells in the field (pressures, daily drilling reports, wireline logs, leak off tests and rock mechanical tests).A geo-stress model was developed, including pore pressure model, minimum and maximum horizontal stresses, and overburden stress. The in-situ horizontal stress directions were estimated from caliper logs, image logs and other field data. Formation rock mechanical properties were obtained using a program which utilizes the log data from the field and estimates the more representative static mechanical properties, which were then calibrated with the lab results. The combined geo-stress and mechanical properties models were calibrated with respect to drilling induced fractures and breakouts observed on the image logs. The calibrated models were used to estimate the required mud weights for drilling under various degrees of underbalance. Instabilities (breakouts) associated with each degree of underbalance were also quantified. The required mud weights to avoid shear and tensile failures, or the expected breakouts for a given mud weight, can be estimated from the generated contour plots for any borehole azimuth and inclination in the field.The results of the study were successfully implemented in the field, resulting in cost benefits of $1MM over five wells. Lost circulation was significantly avoided, and improvements in drilling rate as well as savings in rig days were achieved.The outcome of the study is expected to provide guidelines for underbalanced drilling for future wells in the area.
Improved Production in Low-Pressure Gas Wells by Installing Wellsite Compressors
Authors: Behl N. , Kiser K. E. , Ryan J. 
Published: December 2007

Abstract
Production from low-pressure gas wells was improved by widespread/extensive installation of well site compression in the Waddell Ranch Project. The Project was implemented in three phases over a period of three years beginning in June 2000. A total of 63 wells have been tested with well site compression; there are now 52 permanently installed compressors. The candidates were selected by testing the wells in the low-pressure area and additional wells highlighted by the Moving Domain study. Compressors were installed on successful test candidates in phases one and two. Phase three involved expanding the project to test the remaining 39 gas wells in the area by leasing compressors. This was done to reduce capital cost, take advantage of higher gas prices at the time, and gather data for proper design and sizing of the compressors.
Following studies were carried out as part of the project:
Compare the response of wells in high-pressure area and low-pressure areas of the reservoir to wellhead compression. Feasibility study investigated the field wide compression by use of Central Compression System. This was followed by a study to determine the economics of well site compression versus central compression system. Financial study was carried out to determine the economics of leasing versus purchasing the well site compressors.
The results and conclusion of project were:
Reservoir technologies like Moving Domain study helped in candidate selection. The compressor project has been a success with an average initial uplift of 102 MCFD per well for 52 successful Judkins wells tested. Although the gas production increased significantly the decline rate has also increased indicating that we have accelerated gas production with some addition in reserves. Central Compression system with an estimated project cost of $12 million was found uneconomical. Individual well site compression was more economical method for gas production optimization. A total of $850,000 have been spent in three phases over 3 years.
Several operational improvements evolved which decreased downtime and cost of maintenance and enhanced the profitability of these installations. All these have been listed under the lessons learned part of the paper.
Use of Uncertainty Analysis to Improve Production History Matching and the Decision-Making Process
Authors: Costa A. P. A. , Schiozer D. J. , Poletto C. A. 
Published: December 2007

Abstract
In the present E&P scenario, decisions have to be taken considering risks. An important part of risk evaluation can be accomplished through the evaluation of the impact of uncertainties in the performance of the petroleum fields, yielding higher possibility of success, quantification of possible losses, minimization of sub-optimal development and identification of opportunities.
The objective of this work is to use the quantification of the impact of geological uncertainties to improve the production history matching in a Brazilian onshore field located at Potiguar Basin with 17 years of production history. The main advantage of this process is to provide alternatives for possible adjusted models related to the global rate of liquids, oil and water, allowing the selection of the best model to the be latter refined and adjusted on a well to well basis.
The key point of the applied methodology in the project is the use of the concept of geological representative models (GRM) which are selected based on the integration of objective functions previously defined to the context. These GRM models are selected to represent all combined models which compose the distribution curve (risk curve) of the process. The distribution curve is obtained through the concept of derivative tree technique which combines the possible scenarios using the numerical simulation to predict reservoir behavior. The numerical simulation is used to increase the reliability of the results allowing one more detailed analysis for each model. An automated tool and parallel computing are used to speed up the process.
The utilization of the automated tool as well as a defined methodology to quantify the impact of uncertainties improved the viability of the history matching procedure with a significant reduction of time and effort in the repetitive tasks, improving its results and yielding a more reliable production forecast.
The Impact of Interfacial Tension and Pore-Size Distribution/Capillary Pressure Character on CO2 Relative Permeability at Reservoir Conditions in CO2-Brine Systems
Authors: Bennion B. , Bachu S. 
Published: December 2007

Abstract
Injection of CO2 has been used for enhanced oil recovery (EOR) in many light and medium gravity reservoirs. Consequently, sequestration of CO2 in oil reservoirs in conjunction with CO2-EOR is a method that is under consideration for reducing CO2 emissions into the atmosphere. Many oil reservoirs are underlain by an aquifer, and EOR processes often involve water-alternating-gas (WAG) processes. Proper understanding of the relative permeability character of such systems is essential in ascertaining CO2 injectivity and migration, and in assessing the suitability and safety of prospective CO2 injection and sequestration sites. While many measurements exist for CO2-oil systems, very few data, if any, exist for CO2-brine systems.
This paper provides an analysis of brine-CO2 interfacial tension (IFT) measurements that were conducted for equilibrium brines and CO2 at reservoir conditions, and the detailed 700 MPa mercury-injection capillary pressure tests conducted on all rock samples to determine specific pore size distributions. Three sandstone and three carbonate potential sequestration zones in the Wabamun Lake area in Alberta, Canada, were evaluated, together with a caprock shale. This data set has specific application to the study of the behavior of injected CO2 in contact with bottom water or water-saturated zones that may be encountered in CO2-EOR projects, as well as for CO2 sequestration in deep saline aquifers. The analysis shows some correlation between the CO2-brine IFT, pore size distribution of the intergranular porous media and CO2-brine relative permeability. However, due to the high degree of variability in the pore system character of the different sandstone and carbonate facies tested, additional, better-controlled comparative tests are required to validate these trends. The hope is that, ultimately, compilation of more extensive datasets will allow appropriate selection of proper CO2-brine relative permeability relationships at reservoir conditions for intergranular sandstone and carbonate formations on the basis of relatively simple measurements of pore system geometry and IFT. These data will also provide a valuable tool for the estimation of CO2-brine relative permeability for the simulation and evaluation of intergranular sandstone and carbonate formations on a worldwide basis.
Transforming Data into Decisions to Optimize the Recovery of the Saih Rawl Field in Oman
Authors: Dozier G. C. , Giacon P. 
Published: December 2007

Abstract
This paper will illustrate the collaborative approach taken by an integrated team (operator and service company) charged to demonstrate, within a one-year time period, measurable improvement in well productivity in the Saih Rawl field of Oman. Although the field has been producing for more than five years, the results shown are based on a one-year application of a systematic approach to field optimization. This process is the dynamic integration of historical data and new information, technologies, and engineering diagnostics to systematically identify, layer-by-layer, key parameters affecting productivity and to optimize performance based on "present-state" analyses. In doing so, the program has produced some of the highest productivity wells in the field's history.
Oman has developed into a fast-paced fracturing arena, with challenges similar to those encountered in the tight gas fields of south Texas in the United States. Well productivity is highly dependent on hydraulic fracturing effectiveness and operating practices. Understanding the resultant hydraulic fracture effectiveness is increasingly complicated by the changing mechanical and reservoir properties related to depletion and intralayer communication (crossflow).
Gas is produced in the Saih Rawl field from two distinct main reservoirs: the Barik and Miqrat formations. The Barik formation, at depths from 4500 to 4900 m, is composed of stacked sandstone packages with varying shale content separated by relatively thin heteroliths (sandstone/shale mixtures) of 3 to 7 m thickness. These heteroliths are believed to provide pressure barriers to the various flow units observed in the Barik formation. The Barik formation produces gas of varying richness from most of its units, with a high condensate content produced from layers that are producing currently below dewpoint. On the other hand, the Miqrat formation, found at depths &gt;5100 m, produces lean or dry gas. The combination of relatively low and heterogeneous permeability along with complex hydraulic fracture height growth makes it necessary to perform ad hoc, multistage hydraulic fracturing treatments and to produce these wells commingled to be commercially economic. A systematic approach, incorporating historical pressure trends by unit and theoretical assumptions, validated by indirect field evidence, to onsite decision-making has resulted in the placement of more effective fracture treatments in an operationally efficient manner. The results of these efforts yielded the highest producing well in the field's history in an area of known depletion; the highest-rate Miqrat production well, an overall improvement of zone productivity, and a better understanding of the factors impacting productivity, layer-by-layer, in the Barik and Miqrat formations.
A New IOR Technology To Homogenize Horizontal Well Injectivity/Productivity Profile
Authors: Fernandes P. D. , da Silva M. G. F. , Bedrikovetsky P. 
Published: December 2007

Abstract
Non-uniform distribution of flow rate along horizontal wells results in early water/gas coning, early breakthrough of water/gas during flooding, etc. For injector wells, injection flow rate profile along the horizontal length leads to low sweep efficiency and to large oil-filled by-passed zones.
In the current work, a variable distribution of flow open area along a horizontal well, with or without sand control, is proposed, to correct the flow rate profile along it. An uniform flow profile is achieved by means of unevenly spaced slots or perforations along the liner or sand control device.
An analytical model was developed for flow inside and around the horizontal well with unevenly spaced slots or perforations along the liner or along the sand control device. The model couples flows in well and in the reservoir in well vicinity. The analytical model provides an explicit formula for slot/hole density along liners or screens in injection/production horizontal wells.
Applications of the model to design horizontal well in cases of injection and production, with or without sand control, with inflow control device are discussed.
The technology has been successfully applied in some oilfields onshore and offshore Brazil, where horizontal producer wells were equipped with specially perforated and slotted liners. The purpose is to homogenize flow along horizontal producer or injector wells, in order to delay gas and water coning and improve the sweep. The varying slot/perforation density is calculated by the analytical model, and the calculated option was implemented in some wells.
Best Practice for Fields Producing Below the Bubblepoint
Authors: Thompson M. A. 
Published: December 2007

Abstract
In regulating production on the United Kingdom Continental Shelf (UKCS) the UK Department of Trade and Industry (DTI) has permitted operators, on a case by case basis, to produce below the bubble point locally to the producer well in order to accelerate production or, where pressure support is not economically viable, to produce below the bubble point more extensively.
The maturity of the UKCS means that smaller fields are now being developed and operators are also looking to reduce operating costs in mature fields that are approaching cessation of production (COP). The issue of production below the bubble point is therefore becoming more important.
This paper investigates how operators have been producing below the bubble point over the last decade with the objective of updating guidelines for producing below the bubble point. The success of monitoring techniques is examined and field and well behaviour is compared with common rules of thumb and prediction methods.
Data was collected for 12 fields that had produced below the bubble point in the last 8 years and 5 fields were selected for more detailed analysis. The fields selected represent a cross-section of typical UKCS fields with both vertical and horizontal wells and local and deep production below the bubble point. The analysis techniques include ‘Gas Production Envelope’ calculations, and the use of diagnostic plots of GOR, pressure and cumulative oil recovery.
Of all the fields operating locally below the bubble point, reservoir damage was indicated in only two fields both of which had flowed with bottom hole pressures of about 50% of the bubble point pressure compared with a more normal minimum flowing bottom hole pressure of around 75% of the bubble point pressure.
An Approach for Snaky Well Productivity Under Steady-State Condition
Authors: Qi Zhilin , Du Zhimin , Liang Baosheng , Tang Yong , Wang Shouping , Deng Ruijian 
Published: December 2007

Abstract
As a type of complex well, snaky well is pretty promising especially in the geometrically complicated reservoirs and has been reported recently. Accurate prediction of well productivity is vital. However, conventional productivity calculation methods for horizontal wells could not be applied directly for snaky wells because the production part in the well bore has large fluctuation in the vertical direction and therefore the wellbore pressure drop should not be neglected.
On the basis of the distribution of velocity potential produced in an infinite reservoir by one snaky well, this paper uses the mirror image and the principle of superposition and obtains the velocity potential and pressure distributions for bottom water drive reservoirs with and without gas cap, and edge water drive reservoir. Along the well bore, we then study the flow characteristics and establish a pressure drop model. Coupling wellbore flow with fluid flow in the formation, we develop and further solve a productivity model for the snaky well.
The high precision and practicability are clearly demonstrated using an example. Such well productivity approach reduces uncertainty and better satisfies the real condition, resulting in more accurate prediction.
The Study and Field Applications of Hydraulic Fracturing Technology in Clay-Carbonate Reservoirs with High Temperature, Deep Well Depth, and Densely Distributed Natural Fractures
Authors: Jiang Tingxue , Zhang Yiming , Wang Yongli , Ding Yunhong , Luo Ning , Xu Zejun , Feng Xingkai , Zhang Hongmei 
Published: December 2007

Abstract
A hydraulic fracturing technology is put forward in clay- carbonate reservoirs whose characteristics (take well A as an example) are: 1)deep well depth(4237.5m), high temperature(146 °C), high pore pressure (42MPa); 2)high content of clay(15-22%) and high content of velocity-sensitive minerals (54-71%) such as illite and kaolinite; 3)horizontal stratifications are richly distributed as well as some natural fractures or cavities with high angles; 4) the matrix has a ultra-low permeability (0.0087-0.022 × 10-3μm2) and ultra-low oil saturation(12.3-18.3%). Consequently, the highlights of the hydraulic fracturing technology are: 1) a new fracturing fluid is developed using a super grade Guar as its densifier, with the viscosity of the base fluid being 93 to 102 mPa.s, while the residue content of 197 mg/l. 2) two types of high strength ceramic proppant are used, one is 20/40 mesh, the other is 40/60 mesh; 3) a new kind of mini-fracturing technique is utilized to determine the well head pressure under various pumping rate, near well bore friction pressure, loss coefficient and decrease reservoir temperature and control fracture height as well; 4) a new optimization technique of fracturing treatment parameters is developed systematically,. such as systematic laboratory tests for the fine evaluation of formation, strategy to avoid multiple fractures, monitoring technique of bottom hole pressure, etc.; 5) a new strategy is adopted to help flowing back of fracturing fluid, which takes the stress sensitivity near the well bore and natural fractures’ influences in to account. What's more, the technology has been put in to filed application in the well A, the fracturing treatment is success and the post-fracturing performance is satisfied. Summarily, a systematic fracturing technology is put forward adapted to clay-carbonate reservoirs, and it has a great significance in the near future especially in China.
Tyrihans Field Development Overview
Authors: Munkvold F. R. , Knoff T. 
Published: December 2007

Abstract
Tyrihans is an oil and gas-condensate field offshore Mid- Norway. Oil reserves are 29 million Sm3 and gas reserves are 35 billion Sm3. The field will be developed as a subsea project with 5 templates having 9 producers and 3 injectors. Production start-up is July 2009.
The field development is innovative in the following aspects:
Cost effective development with a 43 km tie-back to the Kristin platform through an 18" pipeline. Tie- back is possible because the pipeline will have direct electrical heating to prevent formation of hydrates and to preserve temperature. Pressure support with both gas injection and raw sea water injection. This is feasible by installing two water injection pumps subsea and using available power and compressor capacity at neighbouring fields. Extensive use of advanced wells. The oil producers are dual-lateral with approx. 1.5 km horizontal reservoir sections, equipped with down-hole ICVs (Inflow Control Valves) and gas lift. Both main bore and laterals will have 8.5" hole diameter, made possible by using 8" expandable liners.
Important reservoir management and simulation issues are:
Tyrihans consists of two structures, which cannot be produced independently. Handling gas and water coning in a two-front system and keeping track of fluid contacts are challenging. The northern structure consists of an 18 m thin oil zone with a gas cap. To simulate recovery from thin oil zones is challenging. The simulation model has horizontal grid, in order to have the required vertical resolution of the oil zone. Correct modelling of pipeline flow and flow assurance. The long, single pipeline tie-back makes well testing difficult. Reservoir monitoring and management must then be based on subsea flow meters and gauges. Production optimization will be performed from an onshore support centre.
With the chosen reservoir development strategy high recovery is obtainable. The simulated oil recovery in the southern part is 52%, and the gas recovery in the northern part is 80%.
A New Model to Describe Formation Damage During Particle Movement and Deposition in Porous Media
Authors: Moghadasi J. , Sharif A. , Kalantari-Dahaghi A. M. , Motaie E. 
Published: December 2007

Abstract
Several investigators have studied formation damage due to invasion of solid suspensions and some modeling approaches have also been reported in the literature, most notably the application of effective medium theory and percolation theory in two and three-dimensional capillary networks. This paper presents a new model, which is based on mass balance transfer function of particles flowing through the porous media. The linear forms of the model are described as well as the radial forms. Although the differential equations derived are similar to the general form of diffusion-convection equations, the marked difference is the suitability of the model, for being applied for variation of parameters, such as particle concentration in the fluid, injection rate, density of solid particles, against the depth and time of invasion. This transfer function is solved by MATLAB program (Version 5.3.2) and SliMULINK software. The results of the simulation run agree reasonably well with the experimental damage data obtained in laboratory.