bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Fracturing Technique Inhibits Post-Fracturing Water Production
Authors: Abdel Meguid Ahmed Ali Mohamed , Waheed Syed Arshad , Yassine Rami , Salem Mohamed , Abd El Aal Ezz El Din Mohamed , Tucker Richard
Published: May 2016

Hydraulic fracturing has been extremely successful in the western desert of Egypt, with approximately 85% of the production resulting from the use of this stimulation technique. However, in many cases the proximity of producing zones to underlying (or overlying) water zones can be a deterrent to fracturing. In the absence of geological barriers, the fracture height can grow uncontrolled during a fracturing treatment into the water-bearing interval and cause unwanted water production. Excessive water production can be detrimental to the economics of a well. By shortening the well's production life and increasing disposal and lifting costs, excessive water production can be extremely detrimental in marginal fields.

This paper presents case histories in which wells were hydraulically fractured using conventional techniques, resulting in higher than 60% water cut, even as much as 100% in one case. While using the conformance-while-fracturing (CWF) method, the water cut was as low as 4%, even when the adjacent water zones were within 20 ft of the perforations. This technique provides a tremendous boost to the economics and an effective solution to a field otherwise plagued with water overproduction. The CWF technique incorporates a relative permeability modifier (RPM) in the fracturing-fluids design. The RPM results in a reduction of effective permeability-to-water without significant changes to the relative permeability-to-oil. This paper describes the geological environment of the El Dour field and discusses properties of the RPM, the CWF job-design considerations, its field applications, and post-fracturing results in comparison to offset wells fractured conventionally. These techniques might be beneficial to other companies faced with similar water-production challenges.

Introduction

As the world's oil-energy demand increases, challenging reservoirs are now being explored. One of the biggest challenges is the water production that normally accompanies the hydrocarbon production. The water can trap the oil and leave huge hydrocarbon reserves unrecovered and also accelerate the fines-migration problem. During well completion, water can increase the chances of corrosion to the surface, downhole tubular, and the chances of scale formations, which can be very difficult to remove once formed (Curtice et al. 2008).

An example of a challenging reservoir is one that does not produce normally without hydraulic-fracturing treatments and has water zones very near to the hydrocarbon zone.

Once these reservoirs are completed using hydraulic fracturing, the water production increases. The problems caused by the water production can be difficult to solve. The case presented in this paper involves one of these reservoirs located in southern Cairo in the western desert, called El Diyur field.
Integration of high resolution 3D seismic and long horizontal well data for predictive structural modeling of the tight Cretaceous Kharaib B reservoir in the Al Shaheen Field, Offshore Qatar
Authors: Prin Cindy , Pedersen-Tatalovic Radmila , Wendorff Maj , Hoch Esbern , Emang Michael Ipui
Published: May 2016

Detailed structural interpretation has been performed to support development of tight and thin accumulations in the Al Shaheen Field, offshore Qatar. The structural modeling has been improved by integration of new high resolution seismic data and long horizontal well data from the Cretaceous reservoir sequence.

Seismic evaluation has shown a relationship between Permo-Triassic structural elements and subtle structural elements in the Cretaceous section. Horizontal well data has provided structural modeling details beyond seismic resolution linking seismic and reservoir observations to reservoir flow unit scale. The integration of the two data sets has resulted in an improved predictive model of fault zones. Individual fault vertical throws of less than 10 feet have been observed associated with natural fracture systems and topographic features such as abundant local circular depressions.

The integration of seismic and well data has allowed building a detailed predictive model providing key input to the challenging development of the thin and tight Cretaceous reservoirs in the Al Shaheen field.

Introduction

The dominant structural features in the Al Shaheen field comprise a conjugate fault system of E-W main strike direction and a less pronounced NNW-SSE striking component. Parts of the field further display well developed northward down-stepping fault blocks. The vertical throws on the faults in the Cretaceous section are generally less than 10 ft, not directly resolvable in seismic. The seismic structural interpretation was carried out with emphasis on faulting in the homogenous Kharaib B carbonate reservoir to allow integration with well data.

The development of the Al Shaheen field includes more than 200 wells positioned in a tight well spacing with ultra long horizontal wells, including world record well length of 40,320 ft, logged with electric petrophysical evaluation tools. The majority of the horizontal wells are drilled in the Cretaceous Kharaib B reservoir comprising platform carbonates. The reservoir characteristics are particularly suitable for detailed structural interpretation from well data as a result of field wide lateral correlation of thin stratigraphic units.
Drilling Rig Fuel And Emissions Reduction Through Regenerative Braking, Load Leveling And Grid Drilling
Authors: Ahmed Shehab , Tafreshi Reza , Palazzolo Alan , Tucker Randall
Published: May 2016

In this paper, we propose to increase the efficiency of drilling rigs DR, through measurement, modeling, adjustment of DR operation, and incorporating an energy storage flywheel system FW resulting in significant reductions in fuel consumption and pollutant emissions. In this regard, we propose to: a) Develop a full system model of all power producing and consuming machinery and process components in the DR and utilize some system measurements and a neural net based identification approach to best fit the model to test data. b) Utilize the model in (a) to investigate alternative operation modes for the drilling rig to reduce fuel consumption and the resulting air pollutants. The model will also guide integration of an energy storage flywheel FW system into the drilling rig to replace a diesel generator DG in order to operate the remaining DG's at more efficient power levels and yet still handle peak power events with the energy stored in the FW. The model will also be employed to simulate charging of the flywheel from the braking energy as a result of inserting (tripping) the drillstring DS into the hole, and the subsequent use of this renewable energy for powering circulation such as pumps, drawworks, lights.

Introduction

A challenge encountered with electric grid drilling EGD is that utilities levy significant surcharges on peak power demand. The flywheel system FW can charge at a constant low power rate from the grid over a long period of time and then discharge its stored energy at the intermittent, transient, high power levels required by the drilling rig. An example of this is that the power required to raise or lower the 250,000 lb drillstring DS by 90 ft. in 20 seconds is approximately 1.5 MW (2,000 hp), even neglecting electrical and mechanical losses. The FW reduces surcharge cost and EGD reduces NOX since power plants emit about 1/25 of the NOX produced by a diesel generator DG for the same amount of electrical energy (MW Hrs).
Technical and Economical Aspects of Self Healing Coatings
Authors: Hatami Boura Saeed , Samadzadeh Mahdi , Peikari Mahmoud , Kasiriha Mahmood , Ashrafi Ali
Published: May 2016

Corrosion in the oil and gas industries is one of the major concerns of the managers and engineers as the main destructive process that lead to huge economic losses. Among all protective methods for corrosion prevention/control, the use of coating systems applied to a metal surface is most important and applicable solution to provide a dense barrier against the corrosive species and postpone their contact with the metal surface. But self healing coating can be considered as an alternate route to further improve the corrosion protection of metals. Self healing coatings are engineered to provide a superior resistance to corrosion on demand when the coating is breached or stressed or when an electrical or mechanical control signal is applied to the coating. Various approaches for achieving healing functionality and the constituents of these coatings and their roles are introduced and discussed. It is tried to some positive or even negative aspects of applying this coating type are mentioned in detail and the most important of them that can have critical effect on economy and industry are introduced.

Introduction

Results of a study, entitled "Corrosion Costs and Preventive Strategies in the United States," which was conducted from 1999 to 2001 by CC Technologies Laboratories, Inc., with support from the FHWA and NACE show that the total annual estimated direct cost of corrosion in the U.S. is approximately a staggering 3.1% of the nation's Gross Domestic Product. It reveals that, although corrosion management has improved over the past several decades, the U.S. and also other nations must find more and better ways to encourage, support, and implement optimal corrosion control practices. "Implement advanced design practices for better corrosion management" and "Improve corrosion technology through research, development, and implementation" were two of three technical suggested strategies that can be used for better corrosion prevention/management. Corrosion in the oil and gas industries is also one of the major concerns of the managers and engineers as the main destructive process that lead to huge economic losses. Both upstream and downstream parts face this problem and the companies spend billions of dollars in this case. To remain competitive with the world market and win the game, this cost must be kept to a minimum and here the large demands for reliable corrosion preventive methods do exist which we can use in our decision making.
3D Stochastic Stratigraphic Well Correlation of Carbonate Ramp Systems
Authors: Lallier Florent , Viseur Sophie , Borgomano Jean , Caumon Guillaume
Published: May 2016

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

1) Introduction

In the static and dynamic workflow of carbonate reservoirs, stratigraphic correlation of well data is one of the first and most influent steps. Indeed, facies distribution and petrophysical properties mainly control flow simulation and are often computed thanks to geostatistical methods, on grids based on stratigraphic correlation and structural data interpreted from seismic data (Borgomano [2008]). In reservoir uncertainty modeling approaches, a unique grid is built, and uncertainties about layering geometry, facies distribution and petrophysical properties are handled using multiple geostatistical simulations (Charles et al, 2001). This article aims at assessing uncertainties due to stratigraphic correlations by also generating several set of possible stratigraphic well correlations. Several grids may then be built from these results and used for facies and property modeling. The method presented here generates automatically and stochastically sequence stratigraphic correlations of carbonate ramp systems by hierarchically integrating multiple pieces of 3D information as: interpreted well data,correlation lines extracted from seismic, andinformation obtained on analogs.

2) 3D Stochastic Stratigraphic Well Correlation method

To perform the correlation, we propose a multi-dimensional and stochastic extension of the Dynamic Time Warping Algorithm (DTW, Myers et al., 1981) that we call msDTW. The DTW algorithm provides a way to find the optimal alignment between two time series [Myer et al., 1981]. This algorithm was used for the correlation of two wells by Smith and Waterman [1980], Howell [1983], Waterman and Raymond [1987], Griffiths and Bake [1990], Brown [1997] for example. Lallier et al. [2009] presented an improvement of the DTW, making the method stochastic and introducing a hierarchy to mimic the reasoning made by sedimentologists when correlating well data (Fig. 1), and applied this method to a carbonate ramp system.
Effect of LoSal on Wettability and Oil Recovery of Carbonate and Sandstone Formation
Authors: Zekri Abdulrazag Yusef , Nasr Mohamed Sanousi , Al-Arabai Zaid Ibrahim
Published: May 2016

Modification of injection water salinity to improve oil recovery is not a new idea and the process has been investigated as far back as the 70's prior to the use of other chemical processes to improve oil recovery. In practice in planning water flooding project oil companies focused only on the compatibility of injection water and formation water issue to eliminate any possibility of formation damage. Many investigators recently had focused their research on the role of water salinity alteration to improve oil recovery. A number of possible mechanisms concerning alteration of water flooding salinity have been proposed in the literature. This project describes an experimental investigation of contact angle changes as function of time, and water flood performance using limestone and sand stone rocks for various injection brines. Carbonate rocks, sandstone rocks obtrained from a Libyan oil reservoir, high salinity water, sea water, low salinity water, and water contains different sulfate concentrations were employed in this study. The results of this research will shed more light on the mechanism of modified salinity flooding (MSFTM) and will help operating companies to better plan water flooding process.

Introduction

Water flooding has been used for many years to improve recovery from oil reservoirs. In the past, no attention has been given to the effect of the water composition and/or concentration on the possibility of increased oil recovery by alteration of salinity type and concentration. Historically the engineering design of water flooding focused only on avoiding formation damage by making sure no interaction between injected brine and indigenous brine. Morrow et al. (1996) concluded that alteration of brine composition of injected water can result in optimization of oil recovery. Tang and Morrow 1999; and McGuire et al. 2005, investigated further the effect of salinity on oil recovery and they have proved that decreasing brine salinity can improve oil recovery. Jerauld et al. 2008 indicated that more than 20 core floods using low salinity of sandstone reservoirs at reservoir conditions and at secondary and tertiary modes has been reported in the literature. Results of experimental work demonstrated an improvement of recovery efficiency due to low salinity by 5 to 38% and that manifested by reduction of residual oil saturation by 3 to 17% pore volume. Nasralla et al. 2011, indicated that injection of deionized water in the secondary mode resulted in a significant improvement in oil recovery compared to seawater.

Different hypothesis have been introduced to explain the improvement in oil recovery by low salinity water injection. These include interfacial tension reduction, wettability alteration, change in pH (increase) resulting in in-situ saponification, emulsion formation, and clay migration.
Optimized Planning and Placement of Horizontal Wells Improved Well Productivity and Controlled Water Cut in Umm Gudair Field, Kuwait
Authors: Banerjee Tapan Kumar , Fadli Eman Hadad Eaid , Ahmed Fazal , Al-Khalifa Nasser
Published: May 2016

Minagish Oolite reservoir of Umm Gudair field, West Kuwait is a cretaceous carbonate reservoir having active aquifer support. Maintaining plateau rate of production with infill drilling is constrained by increasing water cut due to absence of effective stratified layers. Many of the traditional water shut off techniques and selective perforations were partially successful in delaying upward movement of water in wells. But the recent horizontal drilling activity initiated in past 6 years has improved productivity and reduced water cuts in wells.

The selection of well location, trajectory designing and placement of horizontal wells remained a great challenge for UG field. The stress field study, barrier identification and continuous tracking of oil water contact have played important roles in location selection and proper placement of horizontal wells. In UG field all wells are completed with Electrical Submersible Pumps, which dectates dog leg severity of hole and casing designs. Additionally, the higher-up lost circulation zones in Shuaiba and caving shales of Ratawi section restrict early kick off and special mud policies. In the reservoir section, GR and Resistivity responses are monotonous and pose challenge for geosteering. Hence, Image log of LWD tool has been successfully used in picking bed boundary and formation dips to place the trajectory in desired zones.

The evaluation of horizontal well performance in UG field suggest that consideration of critical parameters at planning stage has helped in achieving improved productivity and controlling water cut in wells.

The paper demonstrates how proper understanding of reservoir dynamics and reservoir characterization along with multidisciplinary synergetic approach can lead to a successful horizontal well.

Introduction

The UG field of west Kuwait is mainly a carbonate reservoir, discovered in 1964, produces from the Lower Cretaceous-Middle Minagish formation. The reservoir informally known as the Minagish Oolite (MO) is structurally consist of two doubly plunging anticlines, eastern part is known as EUG and west is called WUG which are connected through a saddle area in middle. About 1/3 of the structural area located in the south (SUG)2, falls in Partitioned Neutral Zone (PNZ) where KGOC and Saudi-Texaco companies are joint partners. The Fig.1 shows the 3D structural view of the area and Fig. 2 shows the oil column in cross section perspectives.
A Combination of Perforating Technologies to Maximize Well Productivity and Minimize Rig Time
Authors: Chadha Nishant , Baumann Carlos Erik , Williams Harvey Alec Rodney , Yokote Ryosuke
Published: May 2016

In this paper we describe the challenges and the techniques used to deliver zero perforation skin wells in the Blacktip gas field offshore Australia. We describe the software models used to evaluate both the well perforation design and the operational risks, and the approach used to reduce rig time. Software modelling based on historical experimental data and newly developed rock perforating models, showed that cleanup with dynamic underbalance would deliver the highest well productivity. Minimum rig time utilization was achieved with wireline conveyed guns. Two methods of deployment were used. To perforate long intervals quickly and safely guns were conveyed on wireline and anchored in the casing with a system that automatically dropped the entire string into the sump after firing. This technique requires less rig time, but it is only applicable to wells with a total gunstring weight lower than the wireline safe working load. The second technique for multiple spaced out payzones used conventional, multiple wireline trips.

All relevant aspects of the perforating jobs, including gun carrier filling after firing, wellbore pressure waves, reservoir flow, and perforation tunnel cleanup were predicted. For each job, guns were custom loaded so as to produce enough dynamic underbalance (DUB) to remove the low permeability crushed rock zone around perforations, thus minimizing perforation skin and maximizing well productivity.

The Blacktip wells were safely perforated for Eni Australia. In addition, we achieved the objective of zero perforation skin and saved more than one day of rig time. The technologies described in this paper can be applied worldwide, saving significant amounts of money and delivering highly productive wells.

Introduction

The Blacktip field is located in the Timor Sea, Australia, approximately 110 km offshore in the Bonaparte Basin, at a water depth of 50 meters.
Oil and Condensate Types In Cenozoic Basins Offshore Vietnam: Composition And Derivation
Authors: Petersen Henrik I. , Nytoft Hans P. , Fyhn Michael B.W. , Dau Nguyen T. , Huong Ha T. , Bojesen-Koefoed J.A. , Nielsen Lars H.
Published: May 2016

The Vietnamese shelf contains several petroleum-producing Cenozoic rift basins, including the Song Hong, Cuu Long, Nam Con Son, and Malay-Cho Thu basins. This study describes geochemical data of oils and condensates from these basins, including new data from the Song Hong and Malay-Tho Chu basins, and demonstrates the variability in composition and source of the petroleum. The results contribute to a better understanding of oil types and petroleum-generating source rocks offshore Vietnam. All investigated samples contain angiosperm biomarkers (e.g. oleanane, bicadinane) indicating sourcing from post-Late Cretaceous source rocks. The Cuu Long Basin is the major oil-producing basin in Vietnam and the highly paraffinic oils have a lacustrine source (high TPP ratios, low C31R/C30 hopane ratios, Pr/Ph ratios of 2-4) and were generated from rocks within the early- to mid-oil window. Lacustrine oils are also known from wells at the northern margin of the Song Hong Basin, and analyses of offshore condensate discoveries show they were generated from relatively mature lacustrine source rocks. However, oil with a conspicuous coaly biomarker signature occurs in the Nam Con Son Basin. Further, a number of the condensates from the Song Hong Basin contain high proportions of higher land plant biomarkers suggesting significant contributions from coaly source rocks. Recently analysed oils from the Malay-Cho Thu Basin (northern margin of the Malay Basin) have likewise a geochemical composition strongly suggesting a coaly source (high wax, Pr/Ph ratios up to >10, dominance of C29 steranes). Hence, new data together with previous data emphasize that coaly source rocks are important petroleum producers on the Vietnamese shelf. Coal-bearing strata in the syn- and post-rift successions in the Cenozoic basins should thus be considered as important additional source rocks offshore Vietnam.
Concepts in Gas Compressor Station Configuration
Authors: Kurz Rainer , Lubomirsky Matt
Published: May 2016

The number of compressors installed in each compressor station of a pipeline system, as well as their arrangement, has a significant impact on the availability, fuel consumption and capacity of the system. This paper discusses the impact of the type and arrangement of turbomachinery equipment used in compressor stations.

Introduction

The economic success of a gas compression operation depends to a significant extent on the operation of the compressors involved. Important criteria include first cost, operating cost (especially fuel cost), life cycle cost, and emissions. Decisions about the layout of compressor stations (Figure 1) such as the number of units, standby requirements, type of driver, and type of compressors have an impact on cost, fuel consumption, operational flexibility, emissions, as well as availability of the station.

Capital Cost: First Cost and Installation Cost

Capital cost for a project consists of first cost and installation cost. First cost not only includes the cost for the driver and compressor, and their skid or foundation, but also the necessary systems that are required for operating them, including filters, coolers, instruments, and valves, and, if reciprocating compressors are used, pulsation bottles.

Although not intuitively obvious, this is also the area that is affected by driver derates due to site ambient temperature and site elevation: The power demand of the compressor has to be met at site conditions, not at ISO or NEMA conditions.
The Path to a Real-Time Optimized, Integrated Gas Network - Smart Fields Applied
Authors: Gobel Derek , Cramer Ron , Briers Jan , de Boer Frank , Lai Kok-Lam , Hooimeijer Martijn
Published: May 2016

This paper describes the successful application of Real-Time Optimization by Shell Malaysia E&P on the Integrated Gas Production System in Sarawak, implementing models for real-time monitoring and optimization of wells and facilities on a gas production network spanning more than 100 wells on more than 40 platforms across a number of different Production Sharing Contracts. We highlight how Digital Oil Field practices enable field-based data to be turned into information, support decision making, and lead to actions that ensure production is optimized continuously.

The technology described in this paper is applied to achieve consistent gas supply to meet demand, maximize revenue, and enable improved and timely operational decisions - striking a balance between short- and long-term value, and taking into account the reality of commercial and contractual constraints, finance, and economics. The optimization is data-driven and covers more than 1,000 variables and features multiple, mutually dependent objectives and constraints.

The solution has proven significantly better than prior physical model-based solutions, which deliver optimized field settings, but with inherently unstable results, and not fast enough for application in a real-time decision making environment. Field trials have proven a result of: increased condensate production at current or improved expected Ultimate Recovery, whilst maintaining a stable gas supply, fulfilling quality constraints and contractual LNG nominations.

This is one of the first successful attempts to implement truly-real-time optimization in a production environment of this size and complexity, including a complicated set of commercial and contractual constraints, and striking a transparent balance between short-term and long-term value. Having proven that a multi-departmental reality can be successfully captured and modeled, might markt the start of a transformation towards embedding intelligent energy to its true potential.
Sequence Stratigraphy of Clastic Overburden of the Miocene Carbonate Play in Central Luconia, Offshore Sarawak, NW Borneo: Implications for Hydrocarbon-Retention Capacity
Authors: Kosa Eduard , Hafrez Amirool , Boey Kenneth , Anuar Azhar , Wee Geoffrey
Published: May 2016

Introduction

Central Luconia, offshore NW Borneo, is a mature gas province with over 45TCF of gas discovered to date in Miocene carbonate build-ups buried under Miocene-Recent deltaic clastics. Most commercial discoveries to date are in carbonate platforms whose large areas contain substantial hydrocarbon volumes even with relatively short columns. However, the remaining prospectivity resides mostly in pinnacle-shape carbonates where commercial volumes require long hydrocarbon columns (Fig. 1A).

Overburden Sequence Stratigraphy

Central Luconia has been characterized by tectonic stability throughout the Miocene resulting in depositional cyclicity and carbonate-clastic interactions chiefly reflecting eustatic sea-level variations. It thus differs from the surrounding basins (i.e., West Baram Delta and West Luconia Delta; Fig. 1B) where high subsidence rates have largely over-written the eustatic signal and where the dominant stratigraphic pattern is aggradation with high-relief clinoforms deposited in front of the deltas. In contrast, gentle subsidence across the Central Luconia plateau has produced slabs of relatively thin shallow-water shelf systems characterized by far (up to 150km) and swift migrations of the palaeocoastlines across the flat shelf-top in response to eustatically driven sea-level oscillations. Back-steps of the systems resulting from sea-level rises were followed by swift regressions of the deltas back to the loci of the previous shelf edges (Fig. 2).

The overburden clastic stratigraphy is thus organised into a succession of deltaic to shallow-marine shelf units punctuated by erosional unconformities and flooding surfaces. In a vertical sense, the stacked depositional cycles show a shallowing-up tendency with sand-prone lithologies resting on top of each cycle (Fig 2). In a lateral sense, well-developed clinoforms allow the extent of each cycle to be mapped out, along with internal building blocks such as topsets, foresets and bottomsets (Fig. 3A). The terminal shelf edges for most overburden cycles are found along the seaward limit of Central Luconia (Fig. 3B), suggesting that carbonate build-ups have been repeatedly transgressed by the topsets of the advancing shallow-marine shelves and land-locked during lowstands. The same pattern of cyclicity and shallowing-up trends can be followed throughout the stratigraphy. Strata surrounding carbonate platforms still growing near the current shelf-edge, some 150km from the present shoreline and submerged under some 100m of seawater, are demonstrably fluvial in origin and sand-rich (Fig. 4).
Instrumentation and Automation Project Costs: The Value Evaluation Dilemma
Authors: Chandrasekar Sarah
Published: May 2016

A series of case studies have been performed for both offshore and onshore projects, focusing on instrumentation and automation portions as pertaining to corporate Intelligent Field Instrumentation (IFI) programs. In green field and brown field projects alike, instrumentation and automation has become a de-facto standard of design and operation. As a matter of form, such projects are justified based on reliability and efficiency gains. Project cost for instrumentation and automation can be significant based on a variety of factors such as complexity, uptime requirements, field topology and extent, infrastructure constraints, redundancy, and other IFI constraints.

In reviewing several such implementations we have encountered instances of cost overruns, often driven by late-emerging requirements, requirement changes, and scope creep. In some instances we discovered cost escalation driven by evolving technology, as "new and improved" products have been rapidly entering the market. In green field cases we found cost overruns driven mainly by changes in field development plans, revised well plans and corresponding production tie-ins. In brown field cases, on the other hand, we observed frequent instances of hidden costs related to process redesign, personnel changes, and training required for new monitoring, control, and operational supervision.

In an uncertain market where oil and gas prices have seen extreme swings, all project costs are monitored closely, and any project cost overruns are viewed in a harsh light. In our look-back we note several observations that provide guidance in terms of estimating, budgeting, and contingency planning for instrumentation and automation. A key finding pertains to organizational culture, for which executive leadership must champion the strategic value of IFI programs.

In summary, the real value of IFI programs lies in the operational reliability and efficiency gains through automation, which in turn supports reduced personnel exposure, early warning, safer operations, and disaster avoidance. In light of a strong safety culture, therefore, instrumentation and automation project costs are progressively being regarded as a cost of doing business.

Case Study 1: Mature Onshore Legacy Conventional Gas

This gas asset has been producing from complex layered conventional reservoirs for close to 50 years. Production comes from three principal formations, and the gas quality has been very high, close to 99% pure methane. The field production peaked at a rate of over 300 Mmcf per day in the early 1980's, and then proceeded to decline very rapidly through the 1990's to about 25 Mmcf per day. At that time the operating company undertook some measures to arrest production decline by means of infill drilling and stimulation, and managed to reverse the trend and increase production to over 75 Mmcf per day by the early 2000's. At that time favorable gas prices supported investment decision for automation equipment that targeted personnel safety and operational efficiency.
Open-Hole Completion with Swell Packer Case Study: What Parameters Can't Be Ignored during the Design Stage?
Authors: Horng Chen Jiun , Nordin Noridah , Zaman Nur Hazrina Kamarul , Riyanto Latief
Published: May 2016

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

As the worldwide oil and gas reserve shrinks with the soar of inflation everyday, most operators are looking for more innovative economical well completion design. Since the last decade, swell packer has emerged from pacing technology to commonly well-accepted technology. Today, swell packer technology is the fruit of numerous financial investments in its research and development. Swell packer now can be deployed in water based mud, oil based mud as well as synthetic based mud.

Whilst swell packer advancement continues, open-hole completion design is gaining its popularity in the industry. It offers 360°-complete-sandface-completion communication to reservoir(s) and tubular production conduit. This concept has advanced the conventional limited entrance perforation hole size, phasing and number of perforation shots. As such, open-hole completion has its productivity advantages over cased hole perforated completion. Its larger flow area offers lower drawdown; which leads to lower sand production risk. Coupling the swell packer with open-hole completion application, it makes multiple zonal pressure isolation in the following open-hole completion possible: bare foot condition, predrilled liner, stand alone screen, open-hole gravel pack or even open-hole fracturing packing. Besides open-hole completion duration is much shorter and cheaper than conventional cased perforated completion design.

The utmost extent of swell packer open-hole completion advantage seems invincible, what are the consideration and limitation then? This paper will discuss singular zonal pressure swell packer performance, different case histories of well design using open-hole swell packer in term of surveillance requirement and challenges. To bring the investigation and discussion to another greater height, case history of swell packer swelling effectiveness and its zonal pressure isolation verification will be shared. It breaks the myths of unable to perform swell packer pressure integrity test in open-hole condition.
Doubling the Production from a Mature Reservoir in North Kuwait-Challenges, Achievements & Lessons Learnt
Authors: Chetri Hom B. , Raju Mankala , Alam Harry , Al-Ajmi Hussain Zuyed
Published: May 2016

Sabiriyah Lower Burgan is a clastic reservoir in North Kuwait on continuous production for the last 45 years. The reservoir, on active water drive, has its inherent problem of rapid increase in water cut, the production performance of wells declining drastically after water cut level of 40%. Many wells became idle in the past, with overall well efficiency (ratio of flowing to total number of wells) of 60%. The formal strategy for production had been focused on "keeping the active perforations away from water". Attempts were made in the past neither to install any artificial lift nor to have a campaign for water shut off/new technology applications.

In order to double production within 6 months from the reservoir, extensive review of the performance, intelligent analysis of existing wells, identification of production enhancement opportunities vis-à-vis mapping resources needed, horizontal wells/ ESP installation for the first time, more ambitious ESP implementation than was comprehended earlier; proactive process to quickly evaluate/ implement rig/ rigless workovers; drill/ complete/ connect new wells on priority and the opportunistic utility of newly drilled wells slated for overlying reservoirs in Lower Burgan were the cornerstone of the strategy. This strategy also proved to be a gap-filler to supplement production gaps, if any, resulting due to delays in water injection projects for other reservoirs. The interlinked workflow processes were developed for other reservoirs with ambitious goal of similar magnitude.

The strategy was implemented during 2010–11 with a jump in production to twice the base level. The challenge was carried forward to sustain the oil rates with controlled water cuts.

Proposed paper is a reflection of a quantum change in the mindsets of the professionals to re-prioritize & re-focus on the reservoir management of mature reservoirs and accordingly align the resources to enhance the production delivery at Gathering centre.

Background

Sabiriyah Lower Burgan(SA LB) is a clastic reservoir on continuous production for the last 45 years. It is a prolific reservoir with natural aquifer support. The crude oil quality produced from the reservoir is of light quality with an average API gravity of about 33 degree and % Sulphur of less than 2.8%. The reservoir has cumulatively produced about 40%of reserves so far. The long term production aspirations from SA LB to the asset is quite significant, with expected peak production of about three time the present levelonce the ESP plan is fully operational and planned infill drilling is complete, as per the forecast from simulation models. The reservoir had been under production with all producers on natural flow at a daily rate of about 50,000 bopd (for the last 3–4 years), with average water cut of about 29%.
Hydraulic Fracturing Stimulation Executions in Brunei.
Authors: Talib Norliny , Omar Amirul Sabrin
Published: May 2016

The West Asset of Brunei Shell Petroleum (BSP) is an offshore-based oil & gas production asset with substantial volumes of non-associated gas from deep, low permeability reservoirs. The typical depths of these reservoirs are from ca. 9000 ft to 11000 ft tvdss having a permeability range of 0.1 - 10 mD and porosity range of 9% -13%.

In the past, the completion type for the deep, tight gas reservoirs has been primarily cased-hole and perforated. The production rates has not been sustainable and was observed to decline faster than expected and ceased production, at reservoir pressures significantly higher than expected abandonment pressure. Investigation showed that these wells quit prematurely due to high skin, although the actual damage mechanism i.e. from fines migration, condensate banking, water banking or clay swelling, is still unknown. Production remediation via acid stimulation and through-tubing re-perforation did not achieve the desired results.

Consequently, there is a demand for the West Asset to pursue different completion strategies primarily dedicated to develop deep, tight gas reservoirs. Hydraulic fracturing is one of the completion concepts proposed to test the reservoir producibility performance. Other than a failed "Skin-Frac" campaign attempt in the past, hydraulic fracturing technology has not been widely applied in BSP. With a lack of geomechanics data and fracturing experience, a number of challenges were confronted during well planning and completion design phase as well as during planning and execution of the hydraulic fracturing campaign.

In the past two years, two wells have been hydraulically fractured by bull heading through 4-1/2" monobore completion via frac boat. Therefore, this case study documents the evolvement of completion and hydraulic fracturing strategies, emphasizing the importance of perforation selection, fluid selection and hydraulic fracture designs to the overall outcome of well performance. This paper also captures the operational challenges and learnings experienced throughout the campaign. This campaign has gathered valuable information on fracturing data and provided better understanding on future completion and fracturing approaches for new tight gas wells in the West Asset and similar assets in Brunei.
Storage and Transportation of Natural Gas at Moderate Pressures using Adsorption in Porous Materials
Authors: Cavalcante Celio L. , Rios Rafael B. , Torres A. Euricio B. , Azevedo Diana C.S.
Published: May 2016

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

The use of vessels filled with porous materials to store and transport natural gas at moderate pressures (about 3.5 MPa) and ambient temperature (about 298 K) has been studied as a potential alternative to compressed natural gas storage at high pressures (ca. 20 MPa). The present study provides an experimental investigation of charge and discharge cycles of natural gas in a prototype storage vessel filled with activated carbon and analyses the effect of the gas composition on the adsorption capacity. The adsorption properties were evaluated by measuring isotherms for each component of natural gas in a magnetic suspension balance and compared with the isotherms measured in a storage vessel using natural gas. The selectivities of the main constituents of natural gas in relation to methane were determined and the influence of the pressure on the selectivity was also observed. Although natural gas is composed mainly of methane (ca. 90% vol.), our experimental results indicate that the preferential adsorption of the heavier hydrocarbons and CO2 should be properly taken into account for the evaluation of the behavior of adsorbed natural gas systems along several charge and discharge cycles.
Vital Role of Nanotechnology and Nanomaterials in the Field of Oilfield Chemistry
Authors: Li Long , Yuan Xubo , Sun Jinsheng , Xu Xianguang , Li Shuang , Wang Lihui
Published: May 2016

Nanotechnology has the potential to introduce revolutionary change in the energy industries such as exploration, development and production. Nanotechnology can revolutionalise the additive properties by tuning particle characteristics to meet certain environmental, operational and technical requirements. Nanotechnology produces nanomaterials that are ultra fines in nature, usually smaller than ordinary micro particles and thus has very high specific surface area with enormous area of interactions.

Recent research has indicated that nanomaterials have unique properties for a broad range of applications in the field of oilfield chemistry, where fluid loss control, borehole stability, cementing quality of a well, remediation of damaged reservoirs, hydrocarbon recovery efficiency, oilfield wastewater treatment are of interest.

This paper presents an extensive literature review of assessing the applications of nanotechnology and nanomaterials in the field of oilfield chemistry, investigating the existing problems in the application of nanomaterials in oilfield chemistry, and evaluating the potential technical and economic benefits that nanotechnology and nanomaterials might provide to petroleum development and production.
Innovative Design of the Solid Expandable Tubular to Patch the Casing: Area Below the Previously Installed Expandable Tubular
Authors: Li Tao , Gao Shan , Chen Qiang , Li Yiliang , Han Weiye , Bi Xiuling , Sun Qiang
Published: May 2016

Solid expandable tubular was widely used for casing patching and proved to be cost effective, however, when the damaged area of the casing is exactly located below the position previously applied by this technology, conventional expandable tubular may not be the choice to do the job since the tubular could not be positioned smoothly due to the loss of the wellbore size caused by the previously installed tubular. The paper discussed an innovative design of the expandable tubular to meet this challenge.

Basically the new design involves putting the expansion tool outside the tubular, as a result the expansion ratio could be maximized and the tubular without launcher could pass through smaller wellbore, specifically the outer diameter of the tubular and the maximum diameter of the expansion tool were the same. The tubular could be put upon the inclined plane of expansion tool as it was delivered into the well, the expansion tool was powered by a piston cylinder and an anchor was used to fix the tubular during the expansion.

In the field application, the tubular was equipped with two expansion tools at its two ends, the upper end of the tubular was cut thinner in order to secure the expansion of this part firstly and the expanded tubular do not touch the casing after expansion. After passing through the previously patched area, we used the hydraulic power to expand the upper end of the tubular and then raised the whole set of the tubular upward until it was stopped by the lower end of tubular installed last time, the mechanical plus hydraulic force were applied to finish the whole expansion, the field experiment was a success.

This innovative design will further enhance the passing ability, expansion ratio and filed efficiency of the expandable tubular; preparing this technology better performance in the mono-diameter well.
Assessment of Multistage Fracturing Technologies as Deployed in the Tight Gas Fields of Saudi Arabia
Authors: Al-Ghazal Mohammed , Al-Driweesh Saad , Al-Ghurairi Fadel , Al-Sagr Abdulaziz , Al-Zaid Mustafa
Published: May 2016

The increasing demand for oil and gas resources to support the worldwide development plans means that the petroleum industry is always actively engaged in exploring new frontiers in drilling and production, including tight multilayered reservoirs. It is becoming evident, more than ever, that producing the most oil and gas out of the drilled reservoirs is an absolute necessity. Accordingly, completion techniques have presented themselves as a crucial well construction parameter and a key to optimally producing wells.

Several completion techniques have been exhaustively trial tested in Saudi Aramco to determine the most successful completion mode for each reservoir. Among those various techniques, open hole multistage stimulation has demonstrated superior performance in minimizing skin damage and maximizing reservoir contact through efficient propagation of fracture networks within the rock matrix.

Overall, the production results from wells completed using open hole multistage stimulation systems — as deployed in the tight gas fields of Saudi Arabia — have been very positive. Of the approximately 40 wells where this new technology was utilized, the majority of the wells have met or exceeded the pre-stimulation expectations for gas production. Various multistage open hole completion systems were run over these 40 wells and the production results varied.

This study highlights these systems and discusses their impact during the fracturing operation and the final stabilized well production. This study will also present some case studies in multistage fracturing operations and investigate the operational impact on productivity enhancement. Following the lessons learned and best practices from these experiences, with correct implementation, the findings from this study should increase the probability of having a more successful multistage stimulation job from a productivity standpoint.
Design, Synthesis and Antifungal Activity of Novel Indole Derivatives Linked with the 1,2,3-Triazole Moiety via the CuAAC Click Reaction
Authors: Xu Guiqing , Zhao Jinglin , Jiang Yuqin , Zhang Peng , Li Wei
Published: May 2016

A series of novel indole derivatives linked with the 1,2,3-triazole moiety was designed, synthesised by the CuCl2/Zn-catalysed Huisgen cycloaddition and characterised. The antifungal activity of all the prepared compounds against Colletotrichum capsici and cotton Physalospora pathogens was evaluated and the results indicated that these compounds showed inhibitory effect for fungi and the inhibition ratio of the best was up to 83.3%. The preliminary structure–activity relationship is also discussed in this paper.
Comparison of Echocardiographic Patterns between Mild to Moderate and Severe CKD with type 4 Cardio renal Syndrome Patients
Authors: Banerjee Sajal K , Zaman SM Mustafa , Ghosh Rajesh K , Hoque Harisul
Published: May 2016

Abstract not availableUniversity Heart Journal Vol. 11, No. 1, January 2015; 02