bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Drilling Performance by Wellbore Stability and Pore-Pressure Evaluation in Deepwater Exploration
Authors: Klimentos Theodore 
Published: February 2016

Abstract
This paper discusses the most important drilling hazards related to borehole instability and pore pressure in deep water wells. A case study from a deep water well, which has experienced wellbore stability and loss of circulation problems, especially over intervals with higher angles of hole deviation, is presented. The answers provided by the study included properties, such as, recommended mud-weights (minimum & maximum) as a function of angle of deviation, rock strength and computed pore pressure. The determination of rock strength along with the optimum mud-weight windows improved overall the drilling performance in the next deep water well by minimizing washouts, loss of circulation and optimizing casing design by elimination of unnecessary casing strings. Moreover, improvement of bit performance was achieved by using the predicted rock-strength values. As a result, drilling time and well construction costs were significantly reduced.

Introduction
Wellbore stability and pore pressure related issues, especially in deep water blocks, cause frequently serious problems during drilling, logging and production operations. The narrow pore pressure and fracture gradient (PPFG) windows necessitate multiple casing strings to reach the target reservoir formations. Errors in predicting PPFG windows could result in significant loss of rig time and even failure of wells.
The removal of rock during the drilling operation disturbs the natural rock formation that is being subjected to a state of compressive in-situ stresses at depth. The redistribution of the stresses around the hole thus produces stress concentrations at or near the borehole wall. Such a high stress buildup around the wellbore may lead to a number of hole problems that include stuck pipe, borehole collapse, sloughing shale and excessive fill. Several billions of dollars are lost each year worldwide directly or indirectly caused by wellbore stability and pore pressure related problems. Therefore, in order to fully obtain the benefits of the directional drilling technology, wellbore stability analysis and pore pressure prediction has been of increasing demand in the planning stage of the wells, especially in deep water where exploration and field development costs are very high.
A Method To Simultaneously Describe Gravity and Imbibition in Fractured Reservoir Simulations
Authors: Boerrigter P.M. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
In densely fractured reservoirs one has to rely on natural mechanisms like capillary imbibition or gravity to recover oil from the matrix reservoir rock. Capillary forces are an efficient displacement mechanism for rocks that are waterwet: these rocks prefer to hold water over oil and, once exposed to water via the fracture system, strongly absorb water thereby expelling oil to the fracture system, from where it can be produced. The alternative situation, where the rock prefers to hold on to oil, also exists (oil-wet or mixed wetrock). In such cases, the most effective way to produce oil, is to rely on gravity. By depletion or via gas injection a gas cap can be formed in the fractures system. This gas surrounds the oil in the tight matrix rock and, because gas has a lower density than oil, the oil will start to drain from matrix stacks into the fracture system due to gravity. In actual filed cases, usually both gravity and some degree of imbibition contribute.
The standard approach in fractured reservoir simulators is to describe fractures and matrix rock as separate systems that can interact with each other(the dual continuum approach), where interaction between matrix and fracture system is governed by shape factors. A proper description of GOGD processes in reservoir simulators is complicated by the nature of gravity to act only vertically and not in all directions as is the case for imbibition and depletion. This paper describes an extension of the dual continuum methods that allows a simultaneous accurate description of gravity and imbibition processes. A comparison is made with methods proposed in the literature and available in commercial simulators. The method has been successfully applied to study fractured reservoirs where gravity and imbibition effects both contribute.
Improved Production From Mature Gas Wells by Introducing Surfactants Into Wells
Authors: Jelinek Wolfgang , Schramm L.L. 
Published: February 2016

Abstract
A very common problem of mature gas fields is liquid loading. If gas wells suffer from liquid loading production is decreased. If most or all the wells suffer from this problem, then effectively the recovery factor and reserves are reduced. Therefore engineering and operational attention is required to improve operational performance through production enhancement and optimisation.
The reason for liquid loading is liquid accumulation in the well bore due to increased liquid gas ratio (LGR) at insufficient gas production rate and gas velocity. Liquid loading is not always obvious but can be verified through the critical velocity and nodal analysis. Theoretical and field investigations deliver a wide range from 5–20 ft/sec for the minimum critical velocity for continuous removal of liquids.
There are several production enhancement techniques available to accelerate production and to prolong the effective producing life of gas wells with liquid loading problems. One method is to reduce the effective density and surface tension of the produced fluids by using surfactants as foaming agents. Foaming is an effective method because reservoir energy is utilized. But the application of surfactants to lift liquids has to fit certain gas well production conditions.
A key factor is the selection of the most effective surfactant without damaging the reservoir. The important criteria and tests for screening to determine which surfactant works best include, but are not limited to surface tension.
Depending on technical and economical limitations various methods of introducing surfactants into the well are used and several possibilities have to be taken into account. Batch or soap sticks for example are not only the simplest methods but also solutions with low initial costs. Nevertheless from a certain point automated and continuous injection should be the preferred solution as for example the installation of a capillary coiled tubing.
For managing production decline in mature gas field environments the correct application of surfactants on gas wells with liquid loading is an effective solution. Surfactants are a production optimization opportunity and can be economically used to gain incremental production from depleted gas reservoirs with liquid loading problems.
The Belanak FPSO Project - A Description of the Challenges in Designing and Building One of the Most Complex FPSOS to Date and the First To Incorporate LPG Processing and Export
Authors: New M.E. , Smith J.E. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
The Belanak FPSO was installed in the Belanak Field in October 2004 and should reach full production in the 3rd quarter of 2005. It will form the central production hub for a number of fields in Indonesia's West Natuna Seaarea, including Belanak, Belut, Kerisi and Tawes. ConocoPhillips is the operator for Block B with Inpex and ChevronTexaco as equity partners. Belanak has the capability to process and export 350mmscfd of sales quality gas, up to100,000 bpd of stabilized crude and 23,000 bpd of LPG in separate propane and butane streams.
Flowlines from two 24 slot wellhead platforms transport raw well fluids to the FPSO, where they are processed and exported as crude via a loading buoy, gas via pipelines to Malaysia and Singapore or as LPG to a separate storage tanker to be moored in the Belanak Field. The Belanak facilities are designed for a 30 year life and offer considerable flexibility to accommodate future fields and deal with incoming hydrocarbon streams as well as deal with H2S, CO2, Mercury and Mercaptans.
The vessel was designed and built in Asia with project management and design being conducted in Singapore, the 285m hull was fabricated in China, and the topsides were built and integrated in Indonesia. With approximately 25,000tonnes of topsides process equipment which includes LPG fractionation as well as 1.2 million barrels of oil storage, Belanak is one of the most complex FPSOs built by the industry to date.
This paper will further describe the Belanak FPSO and discuss some of the challenges that the operator and its contractors faced in designing and delivering this production facility on schedule and within budget expectations.
The Control of fracturing and dolomitisation on 3D reservoir property distribution of the Asmari Formation (Oligocene-Lower Miocene),
Authors: Aqrawi Adnan A.M. , Wennberg Ole Petter 
Published: February 2016

Abstract
The Asmari Formation (Oligocene-early Miocene) is the most important reservoir in the oilfields in the Zagros foreland of the Dezful Embayment of SW Iran. The carbonate reservoirs of the Asmari Formation are characterized by low matrix permeability, and effective drainage is dependent on the occurrence of open fractures. The fractures have been formed during the Zagros Orogeny since late Miocene, which is also responsible for the geometry and formation of NW-SE trending anticlinal traps. Dolomitisation is another factor controlling reservoir qualities as dolostones in general have higher porosities than limestones.
The fractures are typically stratabound and sub-perpendicular to bedding. The density and dimension of fractures are controlled by the mechanical stratigraphy, which is controlled by the depositional environment and cycles. In the platform top sequence, the Dunham's (1962) texture classification appears to be the most important factor controlling the Fracture Intensity (FI) rather than the mechanical layer thickness. Mud supported textures (mudstone and wackestone) have higher FI than grain supported (packstone and grainstone). The fracture density is high in the vicinity of faults.
Two main types of dolomite fabric are recognised; finely crystalline pervasive dolomite (&lt;20µ) replacing mud-rich facies; and combinations of finely crystalline replacive dolomite surrounded by coarser dolomite cement (up to 100µ) in grain-supported facies. Dolomites have an evaporitic signature, based on geochemical and petrographic data, with a general upward increase in the abundance of both anhydrite and dolomite. Dolomite replacing the mud-dominated facies occurs as thinner beds, less extensive aerially forming the top of stratigraphic cycles deposited during highstand, and has lower reservoir quality, particularly as microporosity. Contrary, dolomite replacing the grain-dominated facies exists in thicker and more extensive beds forming the bottom of stratigraphic cycles deposited during early transgression, and these have better reservoir quality, particularly if leached or coarsely crystallined.

General Geology
The Dezful Embayment of SW Iran is one of the rich oil provinces in Middle East, see Fig. 1. The structural and stratigraphic features of Dezful Embayment have been investigated continuously since mid-last century (e.g. Haynes and McQuillan, 1974; McQuillan, 1985; Blanc et al., 2003, Wennberg et al. 2006 & 2007, Ehrenberg et al 2007). Most oilfields in this region are asymmetric anticlines having NW-SE trend as in Fig. 1.
History Match of an Old Waterflood: Dealing with Decades worth of Data from Hundreds of Wells
Authors: Belova Natela V. , Berul Ludmila , Sentyurev Andrey V. 
Published: February 2016

Introduction
The main objective of the mature fields development optimization is the value adding through extension of field life. While elaborating field development additions, an operating company meets a number of problems falling into two categories:The problems associated with the quality and quantity of initial data (ID). Very often, when the development history counts more than 20 years, some well data, for instance, formation pressures, become unavailable. Well logs and well tests can be missing, if not properly archived. Moreover, the data may be complete, but the formerly used methodologies (e.g. the use of well cluster metering units) and instrumentation may have an adverse influence on the accuracy of production, WC, injected water, and formation pressure measurements.The problems associated with decision supporting instruments, e.g. a 3D dynamic model, or reservoir engineering analysis, used for elaboration of recommendations.
This paper illustrates the authors' approach to the mature field development optimization, and providing an example from the Schlumberger Consulting Services practice. The project was completed within a 4½-month timeframe.
Optimization of development envisages the following job types:Elaboration of methodology of ID quality control;Creation of a program of idle low-productive or high-WC wells rehabilitation;Building of a 3D full-field geological and dynamic models being able to serve for development optimization, and elaboration of a program of well intervention.
Upon analysis of development history and accounting for the full-field 3D model outcomes, we suggested to the operating company the following ways of making improvements to development:Well intervention programs for selected wells;Rearrangement of existing water injection patterns within the development cells;Redistribution of water injection between the development cells.

Field Brief
The field is being developed since 1970. A total of 1419 wells were drilled (Fig. 2). The target interval is the Bashkirian. Now the filed has 417 active producers and 165 injectors. The oil recovery is driven by water flooding. The Bashkirian contains 7 pay zones. Marked regularities of reservoir parameters distribution and thickness changes have not been revealed.
The absence of geological and geophysical regularities in distribution of parameters and the absence of impermeable seals between pays hampers the assessment of a pay-based reserves depletion.
Reconciling subsurface uncertainty with the appropriate well design using the Mechanical Earth Model (MEM) approach
Authors: Goodman Harvey Edwin , Connolly Peter 
Published: February 2016

Abstract
The involvement of the well engineer (WE) competency from the earliest phases of exploration is reaping economic benefit for major capital projects (single wells costing at least $25,000,000 US). As the geological and geophysical modeling work of the Explorationists matures and the subsurface picture becomes clearer, the appropriate well design flexibility is being achieved using Mechanical Earth Model (MEM) technology. This approach to well planning is particularly beneficial for deepwater exploration.
For deepwater subsalt plays, the capital outlays are immense, with single wells costing up to $100,000,000 US. For these projects, MEM technology has been found to be extremely valuable, particularly in characterizing drilling risks associated with well exit points below salt where in-situ stress perturbations can occur. These stress perturbations are being reliably mapped using MEM techniques and the consequences to borehole stability addressed. An example of principal stress rotation gleaned from a deepwater MEM and the consequences to borehole stability is summarized in this paper.

Introduction
Formation strength and in-situ stress are the key components of the Mechanical Earth Model (MEM) critical to well engineering design. Figure 1 shows rock stress and strength values (yellow shading) that are calibrated to formation properties and offset well performance criteria to the left. For instance, formation layer rock physics or elastic moduli values must be in agreement with the lithology types coming from the geological model and the impact on formation strength and stress character reconciled. Drilling performance for offset wells, such as rate of penetration (ROP) modeling, is also used to constrain the formation strength estimate. Production history is a general term that includes hydraulic fracture and sand production performance in the reservoir. Core data is used to constrain the static elastic moduli values estimated from acoustic data sources.
Figure 1. Mechanical Earth model (MEM) flowchart with key components formation strength and in situ stress.
Figure 2 displays rock physics impact on formation strength and elastic moduli with changing porosity at a single depth. As porosity decreases, the corresponding rock modulus and strength increases. When formation layer modulus is known, and the distribution of these layers is also known throughout the MEM volume, the corresponding stress distribution through this volume can be reliably estimated using numerical modeling techniques. Below it will be shown that in tectonically active areas, the high modulus formation beds are propagating relatively higher in-situ stress across the geological structure.
Planning a Deepwater Well For All Seasons; Platina-2, A Combined Appraisal/Development Well
Authors: Brown Ian James , Ramlogan Marsha Giselle , McMurray Trevor 
Published: February 2016

Abstract
Due to the punitive cost of drilling deepwater wells with 5th/ 6th generation rig rates flirting around $500,000/day, the need arose within the BP Angola Business Unit to plan a combined appraisal / development well as the first well on Platina West; a field which exists on seismic but remains unconfirmed with a well.
The plan for this combined 'well for all seasons'* would have to be based upon high quality seismic and offset information from recently drilled discovery wells on adjacent fields. The expectation was that a cross-discipline team of engineers and geoscientists could plan one well - without recourse to expensive updip / downdip geological sidetracks - to replace the two traditional and sequential appraisal and development well types.
This paper describes the Platina-2 well design and planning process followed to appraise all options and select the best wellplan to meet all the objectives. Given the present high cost and the forecast cost increase of deepwater well operations, the Platina-2 well planning process provides a useful example for future deepwater drilling operations where the two traditional appraisal/development well types can be rolled together into one combined well and save a considerable amount of field development CAPEX.
The Platina-2 well design and its Statement of Requirements (SoR) are now complete and frozen; pending further detailed definition and eventual spud when a slot becomes available in the rig schedule.

Platina Overview
The Platina field is located in the Western region of Block 18 approximately 200 km offshore, Northwest of Luanda the Angolan capital (see figure 1). The structure is a North-South trending, North plunging, antiform formed by salt emplacement. Subsequent graben collapse due to Pliocene-Miocene salt withdrawal has divided Platina into two geographical regions; Platina Main and Platina West (see figure 2). Platina-1 was the first well to be drilled in Block 18 by BP in 1999 and encountered 3 reservoir intervals (M55, O71 and O72) in what is now termed the Platina Main area.
The Platina West field is forecast to cover three unconsolidated sandstone horizons which the Platina-2 well trajectory will be the first to penetrate.
Jurassic Fault Framework and Structural Style in Bahra and Its Impact on Fracture Development
Authors: Banik Nikhil , Singh Sunil Kumar , Al-Dohiem Aref Abdulsalam Abdullah , Al-Ajmi Neema Hussain 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
Jurassic discoveries in Kuwait during recent years have met with potential successes and are among the landmark achievements in its exploration history. In this list, the success in Bahrah area of North Kuwait attracts special significance for its light oil production from fracture dependent permeability/porosity from an otherwise low matrix porosity carbonate reservoir. Middle Marrat and Najmah Formation within the Jurassic are main recognized reservoirs with proven hydrocarbon in Kuwait. The well evidence in and around the area suggests that Middle Marrat Formation in Bahrah area is of mud prone facies in an outer mid ramp to outer ramp setting having low matrix porosity. Therefore, hydrocarbon potential and productivity of Jurassic reservoir dominantly depends upon open fracture net work connectivity. To evaluate this reservoir characteristics and favorable hydrocarbon traps, the structural style of Bahrah and their fault framework were analyzed through detail mapping of the area. The study brought out N-S elongated faults which changed dominantly to NW-SE direction towards north. This change of fault orientation impacted a rotation effect over a considerable area which is expected to develop intense fracture zone. The large Bahrah prospect is also a combination of several independent structural and fault closures associated in a compressional stress system that paved the way for good fracture development. Seismic attributes such as spectral decomposition, edge slices, and frequency related trace attributes coupled with fracture interpretation from core and image logs of the wells have led to infer these fracture corridors. The studies through geomechanical modeling, curvature maps further consolidated the possible recognition of fracture corridors in the area. Use of ant tracking to define the sub seismic scale finer faults and lineaments are identified to track fracture corridors and appropriately placing the well locations with desired deviations to penetrate through more number of fractures.
Seismic Attribute Analysis - An Aid in Fracture Play Mapping
Authors: Narhari Srinivasa Rao , Banik Nikhil , Singh Sunil Kumar , Al-Adwani Talal Fahad 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
Najmah-Sarjelu formations corresponding to the Kimmeridgian-Bajocian stage are established source rocks in the Middle-East. Recent concerted and dedicated exploratory efforts in Kuwait have seen the successful up-grade of these formations in to a potential reservoir rock with the contribution from fracture associated porosity. This paper examines the role of various seismic attributes in the identification of fracture corridors of this play. The data presented here are from the Raudhatain field and North West Raudhatain field areas of North Kuwait. Based on 3-D seismic data a number of seismic attributes such as, Coherency, EDGE, Dip, Dip Azimuth and Spectral Decomposition have been generated in the zone of interest to understand the distribution of the fault network, which in turn has helped in the identification of fracture corridors. The application of these attributes has highlighted the presence of minor lineaments which have an impact on the fracture generation. Following methods were applied in generating the attributes:Window based application along the seismic reflection event,Volume based application in the zone of interest andVolume based application parallel to the very strong Tithonian Gotnia salt reflector.
Integration of these attribute data sets has resulted in the generation of a detailed fault and lineament map of the area. Some of the attribute data were further refined by means of fault tracking algorithms. Multi-volume visualization has helped in identifying areas with higher probability of encountering fracture networks. Exploratory locations were selected based on the integration of these data sets and in structurally favorable locations. Subsequent drilling results have been very encouraging by encountering fractures according to expectations. Application of multiple seismic attributes has evolved into one of the primary drivers of success for this play.