bluuebunny/crossref_metadata_2025_split huggingface dataset:
Intelligent-Thinking Restored Well Productivity in Horizontal Completions Plugged-off by Sand-Deposits: Huge Reward
Authors: Nwoke Linus , Arukhe James , Uchendu Chike 
Published: December 2007

Abstract
This paper presents improved CTU foam cleanout operation for horizontal producers completed with pre-drilled liners and provides insight into the technicalities of optimized removal of sand-deposits in horizontal wells. Excessive sand production (800-lbs/MSTBO) characterized JKJ reservoir in Niger-Delta, with sand-deposits in the doglegs, drastically plugging the wellbore to abandonment and subsequent shut-in on LTP. Wireline runs and previous unsuccessful attempts to gas/nitrogen-lift the wells confirmed existence of sand-plugs along the wellbore. Rigless CTU sand-cleanout operation was performed on five wells using key design and placement techniques. Limiting sand-cleanout to optimized depths at first point where hole-inclination is 90° within the heel gives valuable results. Further cleanout beyond this depth to the toe breaks apart already-formed cohesive sand-configuration (acting as filters) outside the pre-drilled liners into the wellbore, generating massive sand returns of about 30 bbls to the surface thereby increasing treatment costs and adds negligible value to productivity. Each well was treated within six days at an average total cost of $130,000.00. Incremental 1200 bopd was achieved on average per well, given rise to 4 ½ days Pay Out with respect to oil price of $24 per barrel.
Summarily; Good eccentricity, under-balanced cleanout, stable foam quality and incremental oil were achieved with valued engineering thinking and decision.Because much of the production comes from the heel of horizontal wells, cleanout of sand-deposits to the toe adds little value to productivity with excessive / high additional job costs.Treatment duration is reduced and production time accelerated by limiting cleanout of sand-deposits to optimized depths.Severe production fall-off in horizontal pre-drilled liner completions is caused by sand-plugs in the doglegs, which act as mechanical bridge-plugs.Observation not to cleanout horizontal wellbore completed with pre-drilled liners beyond the depth at first point where hole-inclination is 90° within the heel has been established, and reveals that cleanout beyond this optimal depth creates excessive sands to be handled on surface and adds negligible value to productivity.There is threat of possible formation deconsolidation and early production decline when low bed sands are washed out in horizontal section.
Modeling of Hydraulic Fracture Height Containment in Laminated Sand and Shale Sequences
Authors: Miskimins Jennifer L. , Barree Robert D. 
Published: December 2007

Abstract
The results of hydraulic fracture modeling in a hydrocarbon reservoir consisting of laminated sand and shale sequences are presented. Work previously published by other authors addresses hydraulic fracture growth characteristics in layered intervals, but little published information is available for growth in thin-bedded reservoirs. For the purposes of this paper, thin beds are considered to be on the order of less than 6 inches (15 cm) in thickness. In certain reservoirs, there may be thousands of these thin beds involved in influencing hydraulic fracture growth.
The hydraulic fracture modeling is based on data from the North LaBarge Shallow Unit (NLBSU) located in the Green River basin of Wyoming. The NLBSU produces hydrocarbons from the Cretaceous-age Mesaverde interval. This reservoir is comprised of laminated sand and shale sequences. Hydraulic fracturing is necessary for economic production. Actual field data from two NLBSU wells is used in the analysis. The data includes stimulation treatment pressures and information, as well as a radioactively tagged fracture treatment.
The hydraulic fracture modeling software GOHFER is used in the analysis. GOHFER is used based on its ability to approximate decoupled rock deformation with shear-slip, and its extensive use in the industry.
The results of this study strongly indicate that the sand and shale laminations present in the Mesaverde reservoir act as a hydraulic fracture height containment mechanism. Two events are presented as the reasons for this observed containment. First, shear slippage is prevalent due to the numerous interfaces present in the subject depositional environment. These interfaces inhibit fracture growth through shear failure. Second, the contrast in rock mechanical property values between the sand and shale intervals reduce the fracturing energy available for fracture propagation.
Further research in this area is strongly recommended due to the significant oil and gas reserves associated with this type of reservoirs. These additional research areas include laboratory investigations and field work with tiltmeter and microseismic analysis. Meanwhile, fracture modelers are strongly encouraged to evaluate the effects of laminations in their modeling efforts.
Fluid Loss Control – Improvement for HTHP Wells
Authors: Evans Brian 
Published: December 2007

Abstract
Fluid loss control is often a consideration, if not a major engineering exercise, for a wellbore workover or completion operation. When the mix includes high bottomhole wellbore temperature, high reservoir pore pressure and high reservoir permeability and porosity, then the well killing operation can become very complicated. For these reasons many operations include mechanical means of fluid loss control, thereby achieving positive well control for a long period of time without the worry of reservoir damage by fluid invasion and kill fluid byproducts. However, there are some instances, such as tripping drill pipe or tubing in or out of a well, that mechanical tools are not applicable.
Enter chemical fluid loss control. Often referred to as "fluid loss pills," chemical fluid loss control has been associated with everything from shredded newspapers to the latest biopolymers, which may carry carefully engineered bridging solids. While completion operations will hopefully not use bridging solids usually reserved for lost circulation while drilling, the point is that just about everything at hand on a rig location or in a laboratory has been tried as a fluid loss control agent.
For most of these chemical fluid loss pills, the upper limit of endurance is 275°F (135°C), which is the melting point of processed starch commonly found in fluid loss pills. Also, most commercially available fluid loss pills lose temperature stability as fluid density is increased with water soluble salts. A new fluid loss control pill has been designed to provide effective fluid loss control for 24 hours at 300°F (149°C) in a fluid density up to 12.5 pounds per gallon (1.50 specific gravity).
P/Z Analysis of a Mature Gas Condensate Field, Offshore Trinidad
Authors: Baptiste Brian J. , Jagai Tennyson 
Published: December 2007

Abstract
Graphical application of the gas Material Balance Equation (MBE), P/Z plots, have typically been used to predict the gas in place (GIP) of volumetric reservoirs. Few reservoirs however, are truly volumetric and several workers have developed procedures to correct such P/Z plots, particularly in over pressured regimes, for the pressure maintaining effects of rock collapse and/or shale water influx.
The paper examines and discusses the applicability of eight (8) such procedures to the mildly overpressured, relatively low yield, gas condensate Kiskadee Field in which the original GIP is known from late life P/Z data and in which pressure maintaining effects on the early life P/Z data were not previously recognised.
Production, bottom hole pressure, PVT and pore volume compressibility data are used to analyse the early and late life P/Z data of each identified fault block and to determine the extent and causes of apparent early life pressure maintenance as well as observed variations in the degree of pressure maintenance in individual blocks. A modification is proposed to the Bourgoyne procedure that accurately corrects the early life P/Z data of mildly overpressured reservoirs. A further modification is proposed to correct late life P/Z data for the effects of decreasing shale water influx and increasing water saturation. This further modification is successfully applied and results in GIP estimates that are within 3 % of the known volume.
Amherstia Field, Trinidad: Breaking Barriers in the New Millennium
Authors: Pucknell John , Holder Glen , Seesahai Tony 
Published: December 2007

Abstract
Trinidad's giant Amherstia field began production in October 2000. Eight gas wells and two oil wells have now been drilled and completed, with production capability in excess of 700 MMscf/d. Well performance has far surpassed pre-field development predictions, with current forecasts indicating that the current platform capacity of 825 MMscf/d will be exceeded. The paper describes the many innovative steps taken by the Trinidad based, Amherstia team, bringing world-class technology to Trinidad and developing some of its own, including: Completing the largest gas well operated by bp (225 MMscf/d peak rate) and the largest in Trinidad, achieved by drilling Trinidad's first horizontal gas well and using 7" tubing as the production string;Introducing the use of near bit, hole opening reamers to eliminate back reaming;Extending the step out capability of the in house drilling fleet, developing distant oil reserves in an area formerly deemed unreachable.Introducing Shunt tube open hole gravel pack technology to Trinidad;The use of 4 Component, Ocean bottom Seismic and Pre Stack Depth migration to obtain clear and undistorted images of strata below shallow gas.
Due to the risk of sand production all wells are fitted with Acoustic sand detectors and flowlines operated with erosion limits for nominally sand free production. Permanent downhole pressure gauges are used to ensure pressure build up data is collected whenever a well is shut in. This data, together with the "wet gas" meters used at the surface, mean that the well is, in effect, permanently being tested. Plans are under way to increase platform capacity to 1.1 bscf/d.
On the Mechanisms of Mobilization of Residual Oil Left After Waterflooding
Authors: Bidner M. S. , Savioli G. B. 
Published: December 2007

AbstractTo mobilize the oil trapped after secondary recovery by waterflooding, chemicals (surfactants, alcohols, alkalis, etc.) are injected into the reservoir. Chemical flooding has two main effects: 1) the interfacial tension between oil and water phases is decreased, and 2) these phases become partially miscible. A numerical model is proposed to analyze those effects on oil recovery.
Numerical and Experimental Modeling of Non-Darcy Flow in Porous Media
Authors: Belhaj H. A. , Agha K. R. , Nouri A. M. , Butt S. D. , Islam M. R. 
Published: December 2007

Abstract
A numerical simulation of the newly derived Forchheimer's diffusivity equation has been achieved, careful selection of the non-Darcy coefficient (β) and a fruitful discussion on the use of this coefficient has been presented. Although the proposed model has been designed for single phase flow in porous media, with minor modification it can be applied to multi-phase flow cases. Results show that the proposed numerical model is valid for single-phase flow and is functioning in all ranges of flow in porous medium. The point at which the flow breaks from the Darcian trend has been determined and a new dimensionless term, "Be", has been suggested to define the point of deviating from Darcian flow. "Be" has been found to be 0.0526 at 5% deviation from the Darcian behavior.
An experimental model has been designed to examine certain critical parameters experimentally for the purpose of comparing results with the numerical model predictions. A horizontal fracture has been induced to a homogeneous synthetic sample in the direction of flow with changing aperture to study the effect of fractures on flow behavior.
Experimental results have been compared to the numerical model predictions; a satisfactory agreement within the domain of testing has been concluded which in turn encourages the implementation of this model on a field scale.
Unlike other approaches, the non-Darcy coefficient "β" has been determined experimentally which reflects the authors' belief that when possible, "β" should be evaluated based on the same set of data used to determine permeability in the laboratory.
Trinidad's First 500Mmcfd well: Fact or Fiction?
Authors: Kromah M. J. , Lumsden P. J. , Hennington E. R. , Brayshaw A. C. 
Published: December 2007

Abstract
Existing and projected supply conditions in Trinidad's gas market require that, as a key strategic objective, BP Trinidad and Tobago (bpTT) build upside deliverability into its portfolio of producing gas wells.
By challenging well performance limits many gas wells in Trinidad now have the potential to produce at rates in excess of 150Mmcfd. In conjunction with prudent reservoir management practice, the widespread deployment of low drawdown completions should allow these production technical limits to be pushed even further. Concurrently optimising the sand face completion, production string and topside facilities, so that system ‘chokes’ are moved downstream, are also seen as key to unlocking this potential.
In December 2001 bpTT's Amherstia field set a Trinidad production record with a single well delivering in excess of 210Mmcfd through 7″ tubing. As part of its existing field development plans in 2003 bpTT plans to raise the single well deliverability bar even higher, towards the 300MMcfd mark.
Elsewhere in the world ‘super-bore’ completions have successfully delivered rates beyond 400Mmcfd1. Within the bpTT portfolio of future field development options there exist reservoir segments, which through the use of ‘super-bore’ completions have the potential to deliver Trinidad's first 1/2 Bcfd well.
Offshore Well Testing and Productivity Evaluation Methodology: Plataforma Deltana Project, Eastern Venezuela Basin
Authors: Da Prat Giovanni , Lindo Octavio , Quintero Eduardo , Molina Rolando , Martinez Jose Antonio 
Published: December 2007

Abstract
This work presents the well-test management design and interpretationmethods that have been implemented to evaluate the exploratory wells of thePlataforma Deltana Project, in the Eastern Venezuela basin. The proposedmethodology has been applied to an exploratory well drilled in this project, itis an offshore gas-condensate well located near the border of Venezuela andTrinidad & Tobago. One important aspect that is emphasized in this work isthe need to test exploratory offshore wells to obtain the basic reservoir andwell productivity parameters, and to provide an estimate of the recoverablereserves associated to the well drainage area. The methodology is based on theintegration of seismic, geology and petrophysical information, to optimize thedesign and time of the tests. In order to elaborate the particular well testingprogram in the best economical way, time is a critical factor in any offshorewell, in addition to get focused on layer evaluation and determining producingfluids properties. In this work the evaluation results obtained from theimplementation of this methodology in two sands is presented.
3D Geocellular Modeling in a Complex Structural Setting: El Furrial Giant Oil Field Venezuela
Authors: Laval A. , Auxiette G. , Echeverria I. 
Published: December 2007

Abstract
This paper presents the building of a geocellular static model of El Furrial, giant oil field in Venezuela. El Furrial field, located in the north of Monagas state, was discovered in 1986. It originally contained about 7 billion STOIIP. The field is approximately 13 km along strike and 7 km wide. It produces from two reservoirs identified as the Naricual and Los Jabillos Formations. The gross thickness of the two reservoirs is about 2500 ft. The oil composition in the Furrial Field changes rapidly with depth from that of a conventional oil (28 °API) at the top of the formation to that of an immovable tar mat, principally as a result of an increasing alphaltene content of the crude.
This full field model is set in highly structural complex reservoir. A new software&s chain, RML (Reservoir Modelling Line) was used and has allowed to build an accurate 3D model respecting the most important geological constrains of the field data. Five separated but integrated applications allow to take into account complex structural setting as well as petrophysical data and a high diversity of sedimentological environments which composed the reservoir.
Two first applications (GeoSurf and GeoSim) are used to build an accurate structural framework integrating complex surfaces and more than 60 main faults. A new simulation option (Pluri gaussian algorithm) of stochastic application (Heresim) provides a better solution to restore complex channel or bar architecture and to attribute properties parameters. The resulting very high resolution geocellular grid (about 350 million of cells), have been successful up scaled in term of rock type, porosity and permeability with the 2 last applications (SimGrid and SimUp) to obtain a coarse model of about 900 thousand cells to be used in dynamic simulations.
Using such a line of applications had permitted to get a very integrated model and to be secure of the existence of a very close link between the resulting static and dynamic models.
Modeling of Reservoir Compaction and Casing Integrity Evaluation Using Reservoir Simulation
Authors: Abou-Sayed Ahmed S. , Meng Fanhong , Noble John E. , Guo Quanxin 
Published: December 2007

Abstract
The paper discusses the impact of reservoir production on wellbore integrity and survivability when the compacting reservoir behaves as a deformable permeable body. The discussion is carried out using results of a numerical geomechanics model developed for estimating reservoir compaction, the subsequent surface/mudline subsidence; and the displacements, stresses and strains along the wellbore trajectories. The model has the unique aspect of efficiently coupling rock geomechanics with the actual reservoir simulation results. The input data include such relevant reservoir properties as pore volume compressibility, net-to-gross, porosity; corner point coordinates of each block from the reservoir simulator (the simulator blocks are identical to the elements used for the geomechanics model), wellbore trajectories and rock properties of the overburden. The deformation, stress and strains in the rock and along the well casings are evaluated at distinct time intervals. The initial, intermediate and final reservoir pressure profiles calculated by the reservoir simulator are central to the calculations. The model also has explicit analytical relationships that can be used to represent distinct variations in overburden lithologies.
In the model the reservoir is divided into many elements, where each element is approximated as a strain nucleus. The model estimates rock deformation in a semi-infinite body using a basic strain nucleus solution. The displacement field within the overburden, induced by reservoir compaction, is generated by integration of the Green&s functions derived in the model using the basic strain nucleus solution.
For any specific well trajectory, the model approximates the deformations and stresses in and above/below the reservoir that are generated on the well casing due to reservoir pressure depletion. The calculated deformations include rock movement within the overburden and displacement along the well trajectories, possible fault movements or bedding plane slippage as well as mudline/surface subsidence.
In this paper the physics and mechanics of the modeling approach are briefly described, followed by some examples. Numerous reservoirs have been evaluated using this model in order to analyze reservoir compaction and related mudline/surface subsidence, and to assess the casing integrity of reservoir wells. The evaluated cases have included onshore, offshore and deepwater offshore scenarios. There have been discreet, "isolated," single reservoirs, as well as multi-reservoir situations and offshore deep-water reservoirs. The results from these analyses have assisted in devising improved strategies for reservoir exploitation and management.
Oil-Base Borehole Image Applications in Thinly Bedded Sand Shale Sequences
Authors: Pavlovic Mitch D. , Mollison Richard A. , Payne C. J. , Gomez German 
Published: December 2007

Abstract
Micro-resistivity borehole image logs are well-established tools of geologist and reservoir engineers. These data are used for detailed reservoir description, providing high-resolution structural and sedimentological data. For thinly laminated turbidite sequences, they are often the only practical method of determining the distribution of net pay thickness in the absence of whole core data. Additionally, micro-resistivity images are used to help select intervals for formation testing and perforation.
The increasing use of oil and synthetic oil-base mud systems to reduce drilling risks and improve drilling efficiency has created an environment that prohibited the use of conventional micro-resistivity imaging devices. Thus, it was imperative to develop a new micro-resistivity imaging technology for oil-based mud systems. This paper summarizes the development and successful application of a new oil-base micro-resistivity imager (EARTH ImagerSM) that brings well-accepted resolution and formation response characteristics of conventional micro-resistivity imaging technology to the non-conductive drilling mud systems.
Combining the EARTH Imager with advanced open-hole logging instruments, such as the multi-component induction log (3D ExplorerSM), significantly improves petrophysical evaluation of thinly bedded sand-shale sequences. The interpretation model is built on a combination of high-resolution information from borehole image logs and the 3D Explorer horizontal and vertical resistivity data. These data are used in the Laminated Shaly Sand Analysis (LSSASM) petrophysical model to determine laminar sand resistivity, hydrocarbon saturation, and net sand pay. In our experience, such an approach provides a volumetrically balanced system that is highly reliable for predicting the production potential of an exploration well, a critical step when allocating resources for new development projects.