bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Intelligent-Completion Technology in a Triple-Zone Gravel Packed Commingled Producer
Authors: Brock W. R. , Oleh E. O. , Linscott J. P. , Agara S. 
Published: December 2007

Abstract
Many oil fields are comprised of stacked reservoirs, each requiring multiple individual wells for their proper and timely depletion. By commingling multiple reservoirs in a single well, the total number of wells required for full field development can be significantly reduced and the depletion life can be better managed within the design life of the attendant facilities. This can result in a significant cost savings over conventional development especially in the offshore environs.
Historically one limitation of commingling has been the inability to fully optimize the recovery of the reserves from each interval. In many areas, commingling is restricted or prohibited by regulation because of this inability to optimize the depletion of the reserves. Use of intelligent completion techniques can provide the capability to properly manage the recovery of reserves from each individual zone in a commingled completion.
As a follow-up to a recent discovery, Mobil Producing Nigeria Unlimited (MPN) drilled a long-reach producing well in the Usari field from an existing platform which was completed as a commingled producer in three of the seven discovered zones. Each of the three zones was completed with a gravel pack, a hydraulically operated multi-position flow control valves and downhole gauges which provide full control of each zone. This approach allows for the assessment of the characteristics of each reservoir and proper assessment of the uncertainties associated with a full development of the discovery prior to committing to new wellhead platforms. In addition, the average first-year rate for the well was approximately 11,000 BOPD whereas a single producer would have only provided about 7,000 BOPD.
This paper will focus on the concept selection, interaction with regulatory agencies, the installation and the performance results-to-date. The discussion will also address the reservoir surveillance and management of the three commingled reservoirs including production back-allocation and optimization.
This application is the first recorded use of hydraulically operated multi-position flow control valves (FCV) in a 9-5/8″ triple-gravel packed completion. The learnings from this well are in the area of well planning, equipment installation and reservoir management.
Awakening an Old Field – A Case Study of a Refracturing Program in the Greater Green River Basin
Authors: Shaefer M. 
Published: December 2007

Abstract
Restimulation of wells completed in the Frontier Formation, a low-permeability (e.g., 0.01 – 0.05 md) gas sand, has proven to be successful in the Fontenelle Field. The field is located east of the Fontenelle reservoir, on the LaBarge Platform in the western part of the Greater Green River Basin in southwestern Wyoming. In this area the majority of hydrocarbon reserves in the Second Frontier are produced from the massive shoreface sandstones locally known as the Second Bench of the Second Frontier (Kf22b).
To date, Berco Resources, LLC has increased reserves in the Fontenelle Field by restimulating four wells producing from the Frontier Formation with massive hydraulic fracturing treatments. Due to the success of these treatments, another operator in an offset area to the north has also successfully implemented a Frontier refracturing program. This paper summarizes the refracturing program and the success that Berco Resources, LLC has realized. The candidate selection process is examined, as well as operational considerations when restimulating old wells. The stimulation treatments and fluid systems are also investigated. Daily\monthly production data consisting of gas, condensate and water rates along with well head pressures are evaluated for all cases using fractured well type curves, the pseudoradial flow specialty plot (Δp/q vs. log t) and a production simulator comparing actual versus modeled production rates. Finally, the impact of the refracturing treatments on economic return is presented. The success of the refracture treatments has led to a new drilling\completion program in the Fontenelle Field in 2006 by an operator that recently acquired the Berco Resources, LLC properties.
Using Neural Networks for Candidate Selection and Well Performance Prediction in Water-Shutoff Treatments Using Polymer Gels—A Field-Case Study
Authors: Saeedi A. , Camarda K. V. , Liang J. T. 
Published: December 2007

AbstractUsing actual field cases, a neural-network model was developed to identify candidate wells and predict well performance for water shutoff treatments using polymer gels. A feedforward-backpropagation algorithm was used to develop the neural networks. The before and after treatment data for 22 wells treated with polymer gels in the Arbuckle formation in central Kansas were used to train and verify the neural networks.Polymers and gels have been used extensively in field applications to suppress excess water production and improve oil productivity. Field experience has demonstrated that candidate-well selection is critical to the success of gel-polymer treatments. To date, most candidate-well selections are based on anecdotal screening guidelines, which often results in inconsistent treatment outcomes. With only pretreatment well data as input parameters, the neural networks developed in this work can accurately predict the post-treatment cumulative oil production of the well one month after treatment with an average error of 16%, and the post-treatment cumulative oil production three months after treatment with an average error 10%. This is a dramatic improvement over the current method of using anecdotal screening guidelines for candidate-well selections. This method allows the candidate selection to be based on the accurate predictions of treatment outcomes without having to use complicated reservoir models to simulate the well performance after treatment.
Usari BQI Redevelopment—Paradigm Shift
Authors: Alege F. R. , Brock W. R. , Linscott J. , Olopade B. , Etta C. , Chen L. K. 
Published: December 2007

Abstract
Development of low gravity oil is not very common in the Niger Delta due to the large conventional oil development opportunities available and the belief that secondary recovery methods would be required to achieve comparable recovery levels. The Usari BQI is an example of a relatively heavier crude oil reservoir (API 18-20) in a field of about 35 more conventional reservoirs (API 32-44).
Until recently this water drive reservoir had been only partially developed because of the relatively heavier crude oil, adverse oil-water mobility and a strategy of low producing rates to avoid producing high water cuts in the 70ft oil column. A paradigm shift from studies of analog fields in Nigeria and Western Australia led to a re-development campaign which resulted in a nearly 10-fold increase in production and a significant improvement in reserves in less than 12 months.
Reservoir simulation confirmed the analog data from two fields (Australia and Nigeria) and suggested larger tubing to increase liquid off-take, longer horizontal laterals to contact more reservoir area and denser spacing required to achieve higher recoveries and maximize present value of these relatively more viscous oil reservoirs. In addition, a significant portion of the reserves will be captured only by producing at high water cuts for a long period of time. Performance from the seven wells drilled to date has confirmed the paradigm shift.
Following drilling of three new producers and re-drilling four existing producers with longer horizontal laterals and larger tubing, oil production increased from 5,000 BOPD to nearly 50,000 BOPD and ultimate oil recovery is expected to increase by 20% of STOIIP.
This paradigm shift could be applied in the development and depletion of significant non-conventional oil (low API) reservoirs in the Niger Delta area.
The History and Future of U.S. Oil and Gas
Authors: Li Dacun 
Published: December 2007

Abstract
The United States (US) is the most powerful country in the world, politically, economically, and technologically. In the past twenty years, although the Gross Domestic Product (GDP) of the US has not grown as fast as that of China, the US has sustained its robust energy demand due to the large amount of its GDP. Although rich in natural resources, the US has long been an oil-importing country. In 2002, about 54% of its oil consumption had to be imported, and the gap is still increasing. Along with China, the US was one of the main driving forces for the record-high oil prices in 2005, worsened by Hurricanes Katrina and Rita. In this paper, we derive correlations based on solid oil and gas data reported in the past 20 years and then make predictions up to 2025 by using the correlations. In addition, we compare our predictions with those made by the US Energy Information Administration (EIA). Oil demand predicted by us is comparable with that by EIA under the assumption of low economic growth scenario. The gas demand predicted by us is between the base growth case and high growth case predicted by EIA. Gas consumption in the US will increase by 41% from 2000 to 2025 while oil consumption by 27% during the same period. In 2025, 71% of the oil and 26% of the gas consumed in the US will have to be imported. A lot of oil and gas will have to be imported to meet boosting demand, creating tremendous opportunities in marketing oil and gas to the US.
The Geological Use of Pressure Data: Examples from the Development of the Giant ACG Oil Field, Azerbaijan
Authors: Reynolds A. D. 
Published: December 2007

Abstract
The changes in pressure that occur with depth, stratigraphy, location and time are fundamental to recognising flow units and compartments in oil and gas reservoirs. Such changes can be elucidated via a series of established techniques (pressure, datum pressure and depletion pressure) and cross-plots (pressure-depth and pressure-time). Application of these tools, and a new plot (normalised depletion) to the ACG field in Azerbaijan has revealed: (i) field-wide communication over distances in excess of 30km; (ii) dynamic gradients in both a producing oil leg and an active aquifer; (iii) a clear water-flood response; (iv) strong layering, that was partially recognised at appraisal, fully revealed during primary depletion, and is persisting during water-flood, and (v) variations in transmissibility between layers. These insights are critical in the development of an optimised depletion plan, in monitoring the effects of production and injection, and in assessing the strength of natural pressure support mechanisms. Furthermore, these techniques are likely to have widespread application elsewhere, particularly as pressure data becomes more readily available, via new technology such as MWD formation testers, and distributed temperature sensors.
Maximizing Gas Recovery from Tight Gas Reservoirs in Trawick Field
Authors: Meeks M. H. , Susewind K. D. , Templeman T. L. 
Published: December 2007

Abstract
Trawick field has been rejuvenated through the implementation of new completion strategies and an improved understanding of the reservoirs. Trawick is located in Eastern Texas and is a mature gas field with initial development beginning in 1949. The primary productive intervals are the Travis Peak, Pettit, and James Lime. The Travis Peak and James are both considered to be "tight" gas reservoirs with permeability averaging less than 0.1md in most wells.
By late 2001, cumulative gas production was nearly 1.2 Tscfg. Daily production had fallen to less than 40 MMscfg and was declining at a rate of 12% per year. The Travis Peak and James accounted for more than 75% of daily production at that time. The Pettit was thought to be mostly depleted, so additional production buildup potential was from the James and Travis Peak.
A redevelopment program was initiated in late 2001 to test the feasibility of horizontal completions in the James reservoir. The first few wells performed below expectations. Several mechanical problems were also encountered during drilling and completion operations. An integrated technical effort was initiated to improve the program performance. A high quality 3D seismic survey was acquired and analytic reservoir models were constructed to simulate existing wells. The models and seismic combined to enhance understanding of the reservoir and point out improvements regarding wellbore design, location, and completion techniques that would increase performance of future wells.
The resulting 31 wells (30 horizontal and 1 vertical) were completed in the James by August of 2005 with total daily gas production exceeding 60 MMscfg/D. The drilling program is ongoing and the Travis Peak is now under redevelopment.
Effective Heavy Post-Fracturing Proppant Cleanout with Coiled Tubing: Experimental Study and Field Case History
Authors: Li J. , Bayfield I. , Paton G. 
Published: December 2007

Abstract
Bauxite ceramics are a high strength proppant, which is often used for fracturing stimulation in deep and hot wells. Due to its higher specific gravity (3.5 – 3.6), it is very challenging to design and execute the post-fracturing proppant cleanout with coiled tubing (CT) successfully in the highly deviated large wellbore.
In a sand cleanout with CT the solids are moved by two modes of transport: circulation and wiper trip, in which the localized fluidization is caused by jet turbulence. The jetting turbulence is produced by the down hole wash tool, and as the CT is pulled from the hole it fluidizes and propels the solids in the direction of the wellhead. Some of these solids may stay in suspension and be circulated out of the well depending on the flow velocities, hole geometry and fluid choice. The remainder will tend to fall out of the flow channel downstream from the wash tool. These solids will be continually refluidised by the movement of the wash tool. The speed with which the wash tool can be pulled out of the hole is a complex function of the choice of fluid, flow velocities, hole geometry, hole deviation and the physical properties of the particles. When conditions result in complete removal of the solids, the corresponding maximum value of the CT speed is defined as the optimum wiper trip speed.
In this study, the solids transport test results with bauxite in a full scale flow loop are summarized and four case histories performed on both subsea and land wells are presented. The engineering, implementation and challenge of CT post-fracturing sand cleanout for each individual field case are discussed. The paper also describes how to use a customized down hole switchable wash nozzle and a sophisticated solids transport computer modeling software to optimize the post-fracturing sand cleanout process with 100 % removal efficiency.
New Methods for the Nonequilibrium Initialisation of Reservoir Models With Lateral and Vertical Variations in the Initial Fluid Composition
Authors: Gibson A. , Sørensen H. , Abdou M. , Sener I. 
Published: December 2007

Abstract
New methods have been developed to initialise a compositional model for a giant Middle East reservoir where the initial H2S mol% varies laterally from close to 0 to around 20 and vertically from close to 0 to around 20, being highest at the lower parts of the reservoir.
Conventional initialisation methods assume equilibrium, assigning the same composition to any grid block at a given depth. Two different new method, triangulation and surface-fit, are used to capture observed lateral non-equilibrium variations. Vertical variations in fluid composition are simulated using a gravity segregation model as in the conventional method. The non-equilibrium methods use data on the variation in fluid composition and pressure derived from 18 representative fluid samples collected from wells early in the field history.
The stability of both non-equilibrium methods was initially verified through no-production reservoir simulations.
Simulations were carried out to compare results using the conventional equilibrium method and the new non-equilibrium method. An improved level of detail was verified by monitoring the development of H2S mol% in the produced fluids in three selected groups of wells from regions of the reservoir with different initial levels of H2S mol%.
Field development planning is greatly improved as production predictions now incorporate the regional variations in H2S mol% into the future. Same level of detail can be obtained for other components from the same simulations. As the more sour areas of the field are developed, the new model enables the prediction of H2S mol% and CO2 mol% for the engineering design of new facilities at remote stations and at the main processing plant.
Identification and Characterization of Transition Zones in Tight Carbonates by Downhole Fluid Analysis
Authors: Xian Chenggang , Dawoud Ahmed , Carnegie Andrew , El Mahdi Ahmed , Al Hajeri Salma , Basioni Mahmoud , Raghuraman Bhavani , Fujisawa Go , Mullins Oliver C. 
Published: December 2007

Abstract
In tight carbonate reservoirs, several factors make it difficult to estimate reserves in transition zones. In particular, underestimation of reserves sometimes occurs because the formation oil can be more mobile than expected. The measurement of mobility of the different phases throughout the transition zone, which is affected significantly by complex rock heterogeneity, can only be accomplished by selective flow measurements. To use openhole sampling tools for these flow measurements, it is essential to differentiate between water-base mud (WBM) filtrate and connate water thereby avoiding any negative impact on the oil initially in place (OIIP) calculation and on development decisions. In principle, pressure gradients from traditional open-hole point pressure measurements should help define accurate fluid gradients and contacts. However this procedure is inadequate to identify and characterize the transition zones. Supercharging, capillary effects, changing wettability and saturations, and pressure variations from production and/or injection effects all play a role in complicating interpretation of the pressure measurement data. In addition, gauge effects, depth errors, formation thicknesses and fluid density contrasts yield potentially large uncertainties in interpretation of gradient data.
Downhole pH measurement, embodied within Downhole Fluid Analysis (DFA) procedure, has dramatically improved the situation. Downhole pH measurements utilizing robust pH dyes, the principle behind Litmus paper, have been successfully utilized in differentiating between WBM filtrate and formation water. The downhole fluid analyzers LFA* and CFA* successfully helped determine the level of the anticipated water cut, oil compositions and gravity, and GOR throughout the transition zone allowing a more reliable estimation of hydrocarbon in place and better well placement and production strategies. This process yields considerable cost savings especially by avoiding expensive production tests.
Integration of Surface and Subsurface Models of Commingled Production of Different Reservoir Fluids—Case Study: Gas Condensate Field, Oman
Authors: Al-Marhoon N. , Clark G. , Babajan S. 
Published: December 2007

Abstract
An integration of surface and subsurface models for a deep Gas Condensate field in Oman, containing condensate rich gas in reservoir A (shallower) and dry gas in reservoir B (deeper) is the content of this paper. Production to date was mostly from reservoir A, at which all wells are completed, resulting in the reservoir pressure dropping by 60% in some specific locations from the initial pressure. Furthermore the layered nature of the reservoirs and the varying hydraulic fracturing of the different units, production from the various units differed significantly resulting in significant vertical differential depletion of the reservoir. The field's CGR (Condensate Gas Ratio) has dropped by more than 50% as a consequence of liquid drop out resulting the reservoir A pressure dropping to below the dew point pressure, and the increasing dry gas production from reservoir B through commingled production from some of the wells.
The main challenges in the field is predicting the well performance which is affected by the flow impairment caused by the condensate dropout, the quality of the placed hydraulic fractures in terms of their efficiency and geometry, and completion type, single reservoir or commingled in the two reservoirs (A & B). Also, sealing and non sealing nature of faults play a big role in well performance in the long term. This makes predicting well performance a very complex undertaking.
Integrating Surface and Subsurface models of gas/condensate wells in tight reservoirs with liquid drop-out is still one of the most challenging subjects in reservoir engineering today, especially when it is used as a tool for improving operating philosophy. This integrated project provides an overview of actual reservoir performance in the field over the first 6 years of its production life and the impacts of surface/subsurface integration. For example, high well declines have been observed (upto 50% per annum), the effect of fluid mixture of the rich and dry gas, resulting from the commingled production, the potential cross-flow of the dry gas to the rich gas as was indicated by condensate production and the well capacity, Compression size and timing and operating philosophy. Dynamic models, calibrated by historic production data, are used to assess these effects and to predict future production performance.
Zonal Isolation Modeling and Measurements—Past Myths and Today's Realities
Authors: James Simon , Boukhelifa Linda 
Published: December 2007

Abstract
Over the past ten years, several papers have been published discussing the long-term mechanical durability of the cement sheath. The customary procedure is to use a model to predict potential failure scenarios and to subsequently design a sealant material that will not fail under the expected conditions. The predictive models are either analytical or finite-element models. The analytical models can only be applied to relatively simple situations that require a simplified set of input data. In these cases, the results are consistent with those of finite-element models. More complex situations can be simulated with finite-element models, but the input data requirements are far more severe. Typically in the modeling papers, little information is included on how the input data is obtained. Because of this, several papers have been published that proposed ways to obtain the input data, in particular the mechanical parameters of the set cement. However, because these papers have typically addressed only one or two parameters, the proposed methods are inconsistent. This paper critically reviews the published information; highlights the strengths and weaknesses of the various approaches, and recommends a self-consistent set of measurement methods. The predictions from the given approach have been verified at the field level through evaluation of actual wells.