bluuebunny/crossref_metadata_2025 huggingface dataset:
Oil Recovery Increases by Low-Salinity Flooding: Minnelusa and Green River Formations
Authors: Robertson Eric P.
Published: February 2011

Waterflooding is by far the most widely used method in the world to increase oil recovery. Historically, little consideration has been given in reservoir engineering practice to the effect of injection brine composition on waterflood displacement efficiency or to the possibility of increased oil recovery through manipulation of the composition of the injected water. However, recent work has shown that oil recovery can be significantly increased by modifying the injection brine chemistry or by injecting diluted or low salinity brine.

This paper reports on laboratory work done to increase the understanding of improved oil recovery by waterflooding with low salinity injection water. Porous media used in the studies included outcrop Berea sandstone (Ohio, U.S.A.) and reservoir cores from the Green River formation of the Uinta basin (Utah, U.S.A.). Crude oils used in the experimental protocols were taken from the Minnelusa formation of the Powder River basin (Wyoming, U.S.A.) and from the Green River formation, Monument Butte field in the Uinta basin.

Laboratory corefloods using Berea sandstone, Minnelusa crude oil, and simulated Minnelusa formation water found that at lower aging temperatures, very little to no additional oil was recovered from low-salinity corefloods compared to full-strength reservoir brine floods; while higher aging temperatures resulted in significantly higher recoveries from low-salinity floods than from full-strength reservoir brine floods. Waterflood studies using reservoir cores and fluids from the Green River formation of the Monument Butte field also showed significantly higher oil recoveries from low salinity waterfloods with cores flooded with fresher water recovering 12.4% more oil on average than those flooded with undiluted formation brine.
Advanced Cement System for Acid Gas Injection Wells
Authors: Fakhreldin Y. , Al-Sharji H. , Ruwehy A. M. , Saadi K. , Taoutaou Salim , Al-Kalbani Sultan
Published: February 2011

Petroleum Development Oman, PDO, is planning to improve ultimate recovery of condensate from a retrograde condensate gas field by reducing the rate of reservoir pressure decline. This shall be accomplished by re-injecting into the reservoir some of the produced gas and all of the acid gas extracted from the sweetening process. The composition of the injected gas will vary over time, from 15% CO2 and 3% H2S to 56% CO2 and 10% H2S. These combinations of CO2 and H2S can cause the wells cement to deteriorate. Portland cement tends to strongly degrade once exposed to such acid gases by reacting with calcium hydroxide formed from hydrated calcium silicate phases. As carbonates are dissolved in a low pH environment, the cement-carbonation products will not act as a self-plugging agent / s in the cement sheath. The resulting decrease of compressive strength and increase of permeability could lead to loss of zonal isolation and casing corrosion. These requirements led PDO to investigate and trial CO2-resistant cement to enable zonal isolation and ensure long term containment of the reservoir fluids. The nominated new technology cement system was trailed in a deep gas well which penetrated a reservoir which has high concentrations of CO2 and H2S at a super critical condition. The CBL/VDL log which was run after well completion showed excellent results. The well-cement quality shall be re-logged prior to any zonal shutoff work-over or well decommissioning. This paper will discuss the design, execution, and evaluation of the first acid gas resistant cement in PDO in one of the high profile gas well in South of Sultanate of Oman.
Technical Evaluations to Support the Decision to Reinject Produced Water
Authors: Zuluaga E. , Evans P. , Nesom P. , Spratt T. , Daniels E.
Published: February 2011

The industry is moving away from overboard discharging of produced water and is increasingly selecting produced water reinjection (PWRI) as the preferred method for waterflooding projects. This does not come without risks as the produced water usually needs to be supplemented by seawater in order to meet injection volume requirements, which increases the risk of both scaling and souring.

PWRI supplemented by seawater was the selected produced water management strategy for Field M located in West Africa. Produced water from the adjacent Field K is also being considered for reinjection into Field M. Field M will be waterflooded from the beginning to maintain reservoir pressure close to the bubble point. Recent experiences of PWRI in other assets have created a challenging atmosphere as scaling posed a major risk to production. Field M had to go through very detailed and though souring and scaling evaluations to justify the feasibility of this project.

A consistent formation water chemistry analysis for these evaluations was obtained by incorporating thermodynamic equilibrium constraints on formation water composition from reservoir mineralogy and using knowledge of basin formation water contributions from proximal salt formations. The evaluation of scaling potential was done using ScaleSoftPitzer. The results show a low risk of scaling when the waters are commingled. Periodic formation scale squeezes are recommended to mitigate the scaling potential.

The souring potential study was conducted using a full field reservoir souring simulation model (SourSimRL). SourSimRL superimposes criteria for the generation, partitioning and transport of H2S. Based on the results, the souring potential is predicted to be generally moderate. The souring potential for the field is restricted by the availability of carbon nutrients in the injection waters and the high reservoir temperature of 250 °F.

These rigorous technical evaluations were instrumental to obtain the support for PWRI and could be used as guidance for other PWRI projects.
Flow Quality Indicator (FQI): An Innovative Approach to Permeability Prediction
Authors: Akam Somadina Azuka , Maher Tom , Schell Christiane , Arnott Stuart
Published: February 2011

The Flow Quality Indicator (FQI) is an innovative but simple approach to permeability prediction, developed in response to modeling and production accounting issues. The FQI theory is that, in its simplest form in a unit reservoir, three parameters, in combination, determine the flow quality - porosity, volume of impermeable member, Vimp, and the remaining grain volume or "permeable member", Vpm. FQI postulates that Vpm must expand or contract with variations in Vimp and porosity. This variation is demonstrated to be unique property of any reservoir.

By relating FQI to measured core permeability or an independent measure of reservoir quality, the resultant empirical relationship has been established as a simple predictor of permeability in the absence of core data.

Two empirical model types - quadratic and linear – have been developed from core data in Baram Delta and Sabah (Malaysia). Results from either type do not show significant differences but the quadratic model has been found more suitable for highly laminated thin bed clastic environments below log resolution. The linear model has a more general application in most clastic depositional settings where formation beds are close to log resolution or larger.

The FQI concept has implicit universality, as demonstrated by several successful tests in the Baram Delta (Malaysia), Brunei and the Niger Delta (Nigeria). Coefficients of the function may be fine-tuned using an FQI modeling tool. However, it has been shown that only limited fine-tuning is required for most environments.

The FQI approach offers significant advantages compared with alternative models for permeability prediction (such as the Flow Zone Indicator, FZI), namely: (1) the input variables (Vsh, Φ) can be readily determined from conventional logs; (2) permeability estimation is quick and comprehensive; and (3) the method is applicable over a wide variety of clastic geological environments.
Alternative Training Tactics Provide Deeper Understanding of PDM Principles for Field Operators
Authors: Wakefield Sarah , Matta Stefanie
Published: February 2011

The widespread and longstanding use of the positive displacement motor (PDM) in thru-tubing and other oilfield applications means many tool operators have achieved a measure of both proficiency and confidence with running PDMs. But do operators really understand the mechanics of what makes the PDM work?

The introduction of newer, competing technologies such as turbines for downhole applications means operators and customers now have a choice between different technologies to meet their need for a downhole drive system. Each technology offers different benefits and limitations. To make the right choice for the job situation and for the customer, field operators must have more than just a surface level understanding of the differences between the tools. A training program that would provide operators a deeper understanding of the PDM was required to help meet this need.

Typical ‘tool’ or product training focuses on each tool and lists the features, benefits and limitations of that tool in a lecture format. Retention of knowledge by adult learners in this type of lecture format is typically low. For our situation, we needed to ensure students not only recalled basic information about the PDM, but also learned and retained enough knowledge about the inner workings of the tool to make informed choices while operating on the job.

We chose to apply adult learning principles such as interactivity, repetition and motivation in the development of our PDM classroom-based technical training. From student presentations detailing the motor's internal design to simple visualization exercises using a pencil to demonstrate the movement of the rotor within the stator, we appealed to several different learning styles throughout the training. Survey results offered evidence that the alternative training tactics provided the students a deeper understanding of the PDM.

Information provided in the paper can benefit PDM field operators as well as developers and facilitators of technical training programs throughout the industry. Adoption of adult learning principles as a basis of technical training development can provide excellent results for classroom applications.
Deepwater Developments: Challenging Equipment Limits
Authors: Gordon Jeanette , Saicic Petar , McAllan Robert
Published: February 2011

This paper reviews an operator’s deepwater drilling campaign in Gabon and Equatorial Guinea and the principles that were established to ensure success through optimized performance.

Due to the economics involved in deepwater drilling notably the availability of suitable high specification drilling units, (and the corresponding high operating costs and mobilization times) operators with short exploration campaigns are responsive to considering the use of lesser specification vessels with a different well construction philosophy as a means of both optimizing performance and safely undertaking a project.

For this particular case study, the operator implemented current proven technologies in new ways to extend the previously regarded equipment limitations of a vessel thus providing a fit for purpose and safe solution to the financial and operational roadblocks which could have hampered the project. Specifically the implementation of surface BOP’s on a dynamically positioned drillship along with riserless drilling and evaluation of a shallow gas reservoir well. The key principles employed that ensured a successful campaign were;

Thorough well planning and risk assessment processes Establishing a high objective. i.e. "technical limit" Adapting and innovating to a given situation Logistical planning

The principles employed in this particular success case can be implemented for any project or task in a variety of industries or applications. Ultimately success was attained through thorough planning and subsequently successful execution of the plan.

The result was that this operator was able to drill five wells in the same amount of time as other operators had taken to drill only one well. This paper will detail how world record breaking performance in a deepwater environment was achieved.
Waxy Crude Production Management in a Deepwater Subsea Environment
Authors: Suppiah S. , Ahmad A. , Alderson C. , Akbarzadeh K. , Gao J. , Shorthouse J. , Khan I. A. , Forde C. , Jamaluddin A.
Published: February 2011

Systematic experimental and modeling approaches to designing a safe operating strategy for a 5-km deepwater subsea flowline case study are presented to address unplanned shutdown and restart events for waxy crude production. The measurements confirmed that the fluid behaves like Bingham plastic when it is allowed to become gel at the seabed temperature of 4 deg.C. The cool-down period was modeled using the transient simulator validated by measurements and was predicted to take 21 hours. The restart pressure was then modeled for both stock-tank and at line pressure conditions. These restart pressure requirements were found to be 2,500 psi and 2,100 psi, respectively for stock-tank and at line pressure conditions. Also, the use of inhibitor treatments demonstrated that the fluid would not form gel at the sea bed temperature of 4 deg. C. However, the current shut-in wellhead pressure of 2,500 psi is deemed adequate to restart the lines in the event of unplanned shutdown without the use of chemicals. The presence of a subsea pig-launching pump provides a safety factor for restart in case the line pressure is released to atmospheric conditions. Hence, the operating strategy does not require injection of wax inhibitors at the current state. However, in future when the shut-in wellhead pressure falls below 2,500 psi, the operating strategy is expected to be modified accordingly.
Maintain Well Productivity Through Inhibiting Scale Formation and Controlling Fines Migration
Authors: Nguyen P. D. , Vasquez J. E. , Weaver J. D. , Welton T. D.
Published: February 2011

Migration of fine particulates and/or scale formation is known to plug up etched channels or pore spaces in proppant packs, causing production decline in wells that have been acidized or completed with high-rate water packs or frac-packs. The removal of such damage caused by plugging is only a temporary solution if the source of the plugging material is not mitigated. This paper presents the results of a series of laboratory tests aimed at demonstrating and quantifying the performance of a treatment fluid for stabilizing formation fines, inhibiting scale formation, and keeping flow channels open through damaged proppant packs after production has been restored.

Packed beds of proppant and formation sands were used to simulate frac-pack conditions before and after remedial treatments. The treatment fluid was comprised of a salt-free, aqueous-based solution containing an environmental friendly clay-swelling inhibitor and a water-based agglomerating agent (WBAA). The results show that this WBAA system is applicable to most types of formations, including sandstones, carbonates, and coals. Once injected into the proppant pack and formation matrix, WBAA forms a thin film on the particulates, covering and anchoring them in place, without plugging pore throats. This thin coating does not harden, but remains flexible, allowing the treated formation to withstand high shear stress during high production flow rates. WBAA coating forms hydrophobic film-encapsulating particulate surfaces, inhibiting chemical reactions that lead to scale formation in the pack matrix.

The experimental results show that WBAA treatments effectively mitigate the buildup of scale in various sand packs and successfully control the migration of formation fines into proppant packs to maintain well production.
A Successful Application of Permanently Installed Distributed Temperature Sensing (DTS) for Optimization of Acid Treatment in Power Water Injector with Advanced Well Completion: Case Study
Authors: Sharma Hemant , Al-Zain Ahmed , Al-Salman Naji , Al-Harbi Mesaad , Said Rifat
Published: February 2011

With the advancement of technology and ease of drilling horizontal wells, producers/injectors are drilled with thousands of feet of horizontal section, to expose large reservoir areas for higher production/injection. To have a better flow distribution profile in heterogeneous formations, the producers/injectors are completed with Inflow Control Devices (ICDs) and external packers that provide compartmentalization to flow. The permanently installed distributed temperature sensing (DTS) fiber optic cable is externally attached to the completion, which is fed through the packers. This helps in obtaining distributed temperatures of all formations along the wellbore and throughout the horizontal section with high resolution. On-site analysis of the real time data from DTS could be used to optimize well treatments, such as acid stimulation.

This paper presents in depth analysis of an acid stimulation performed on a power water injector in a carbonate reservoir. The well is completed with ICDs, DTS and a Permanent Downhole Monitoring System (PDHMS) for well and reservoir monitoring. The real time data acquisition of distributed temperatures coupled with online interpretation through a special software helped in building temperature profiles. Analyses of the temperature profiles were used for proper placement of acid and diverter stages. The post acid stimulation result was very encouraging with a significant increase in the well injectivity and even flow distribution along the horizontal section. The experience obtained from this job has been used as a basis for future stimulation jobs.
Microseismic Mapping of Hydraulic Treatments in Coalbed-Methane CBM Formations: Challenges and Solutions
Authors: Zimmer Ulrich
Published: February 2011

Detecting and locating microseismic events that occur during a hydraulic treatment of a coalbed-methane (CBM) formation can be challenging because of the special properties of the formation itself and the specific treatment parameters. Based on experience gained working with dozens of monitored CBM treatments, several specific challenges and their solutions can be identified. Events created during such treatments are usually small in magnitude as a result of the often small injection rates and petrophysical properties of the target formation. To detect these small events over the ambient noise, the sensors have to be in relatively close proximity to the injection. In addition, it is important to reduce the ambient noise as much as possible. Because options to reduce ambient noise are limited, it is imperative to ensure that the sensors and casing are securely coupled to the surrounding rock. In some cases, it is better to place the sensors higher above the zone of interest if a better coupling can be achieved. Another common challenge in CBM formations is the high velocity contrast between the target formation and the surrounding rock, which creates some mathematical challenges in the accurate localization of the events. Extensive model calibration, accurate logs, and clear events in known locations (e.g., perforation shots) can improve the overall location accuracy significantly. Most of these issues can be addressed in prejob modeling studies that quantify viewing distances, location accuracy, and waveform appearance etc., before any microseismic data is acquired. These studies help anticipate potential challenges for particular projects as well as document realistic accuracy levels, which are essential for a comprehensive interpretation of the microseismic-event distribution.
Hydrate Formation Characteristics of Natural Gas During Transient Operation of a Flow Line
Authors: Lorenzo Mauricio Di , Kozielski Karen , Seo Yutaek , Soto Gerardo Sanchez , Zhang Junfang
Published: February 2011

Hydrate management during transient operation of subsea flow lines has been identified as one of the greatest challenges for deep water O&G production. Experiments using natural gas and de-ionized water were conducted in a laboratory flow loop (1" diameter and 40 m length) to investigate the dynamics of hydrate formation during simulated shut-in and restart conditions. Variables studied include different operational pressures and sub-coolings.

This work will provide valuable information for the establishment of cost-effective strategies to guarantee the continuous flow of fluids in subsea production systems, particularly during transient operations such as scheduled maintenance or unplanned shut-downs.

During the shut-in period hydrate appears to nucleate along the gas-water interface and grow as a film that spreads across the entire interface. At a pressure of 1,500 psi and sub-cooling of 15°C, dendrite crystals start to appear at the film and grow into the water phase until a thickness is reached where further grow stops. It is noted that, although hydrate is observed as a thin film during the shut-in period, most of the water is converted to hydrate upon restart. At every pressure condition evaluated in this study, slurry like hydrate flow has been observed upon restart, being flushed along the pipe-line by the gas flow.

Transient operations of subsea flow lines require strict adherence to operational procedures which include depressurization and flushing of the lines with thermodynamic hydrate inhibitors. The results of our work suggest that the blockage is more likely to occur during restart so operating procedures must be designed to minimize the risk of hydrate blockage based on specific factors such as driving force, water content, and gas flow rate. It is considered that the flow loop experiments could provide valuable insight into the dynamics of hydrate blockages formed under flow conditions in gas dominant flows.
A New Approach for the Realistic Evaluation of Very Thin Reservoirs of Krishna Godavari Basin, East Coast, India
Authors: Yadav Lalaji , Dutta Tanmoy , Kundu Ashish , Sinha Neeraj
Published: February 2011

In thin bedded reservoirs high resolution borehole images are generally used to determine distribution of high quality, productive sands. Deep water Tertiary reservoirs of Krishna Godavari basin are generally very complex and heterogeneous, ranging from massive thick sands to highly laminated very thin sand/shale sequences with average bed thicknesses less than the vertical resolution of microresistivity-imaging tool. The image tool responds to the beds and features smaller than the vertical resolution but can not accurately determine laminar bed thickness which can be used as an integral part of low- resolution technique. In the absence of a well defined set of thin bed boundaries from image tools, an integrated of approach of forward modeling and inversion is also impractical for the accurate thin bed evaluation.

A new approach of laminated shaly sand analysis is developed where laminar sand/shale estimation is based on generation of binary lithology on shale volume curve derived from micro-electrical resistivity. Formation beds as thin as the twice of the sampling interval can be generated through this technique in such a way that cumulative net sand fraction is restricted with integrated sand volume. Laminar shale volume from image tool calibrated to the LamCount core data has been considered to be the ground truth in the analysis. The volume of dispersed shale and the total and effective porosities of the laminar sand fraction are determined using a Thomas-Stieber volumetric approach. Water saturation is estimated from laminar sand-fraction resistivity derived from electrical anisotropy.

Application of the methodology leads to an improved accuracy of reserve estimates and productivity predictions. Entire procedure is illustrated with an example of completely cored reservoir section. Results indicate that low resistive laminated reservoirs with very high shale fractions can be highly productive with reservoir quality equivalent or some times even better than massive thick beds.
Turning Around Mature Field Production Performance by Finding and Producing New Pools – A Mutiara Field Case History Of Successful Grid Base Drilling Campaign In Fluvio-Deltaic Reservoir
Authors: Wibowo Icuk Dwi , Sinaga Iranta Bona , Hermawaty Irma , Rahmanto Wahyu Agung , Krisnandya Arief , Srikandi Citra
Published: February 2011

Mutiara-Pamaguan Field are gas - oil field, located onshore in Sanga-Sanga PSC, Kutai Basin, East Kalimantan, Indonesia, consist of numerous complex- stacked-sand of deltaic environment. The challenge to fully develop the field is lack of knowledge on reservoir distribution and geometry. A semi-statistical (grid base) drilling has been applied as development strategy to increase the near term production rate and maximize recovery from these fields. The paper will focus on the "grid base" drilling development concept and actual results.

A justification to drill the wells is used to be focused on the incremental reserves coming from the remaining recoverable reserves of the known-reservoirs that can be predicted by combining the static and dynamic modelling. Unfortunately, hydrocarbon in place and recoverable reserves from the new-pools zones can only be determined after drilling. It is a challenge to predict new-pools zones in fluvio-deltaic reservoir due to reservoir uncertainty. However, the drilling results statistic improves the understanding of relationship between the distances from the new well to the existing wells with the hydrocarbon reserves from the unknown-reservoirs. Based on the complete understanding of known-reservoir and statistical knowledge of unknown-reservoir, a grid base drilling concept was then implemented to further develop the crestal area and to add a take-off point on spares in Mutiara - Pamaguan Field.

The actual results from the last three years have successfully sustained field production. The grid base wells have delivered more than 52 bcf and 2 mmbo of incremental reserves, and turned around Mutiara- Pamaguan production rate. The production performance has increased from 100 mmscfd to 125 mmscfd whereas oil production has doubled from 4000 bopd to 8000 bopd.

Currently grid base wells contribute 75% of that production. In term of development cost ($/boe), a successful of grid bas drilling strategy in Mutiara and Pamaguan Fields is one most efficient field development in Sanga-Sanga PSC.
Using Knowledge Management Techniques and Communities of Practice to Drive Performance Improvements in Drilling Applications in Onshore China
Authors: Perry Phil , Lee Roger , Yao Yan Zhang , Clark-Moore Ross
Published: February 2011

Onshore drilling in China is very diverse, ranging from wells drilled relatively straightforward in a matter of days to more complex geological environments where drilling can take several hundred days. Recently, this market has increasingly opened up to international operators and service companies, presenting opportunities to introduce new approaches to drilling performance optimization. To best capture the performance potential in any given application it is necessary to gain a detailed understanding of the complex drilling and production environment. This requires an understanding of many important variables, including: ○Macro components—Operators, geographic locations, organizational structure, decision makers, drilling activity, achievable market penetration.○External factors—Technology vendors, products, service organization, market strategies, organizational strengths and weaknesses○Drilling applications—Application breakdown, drilling issues, best practices and opportunities

This enables an organization to optimize its technology and service portfolio in a holistic approach to develop system solutions that achieve its objectives and key performance indicators (KPIs), and assist operating companies to overcome drilling challenges, deliver reductions in non-productive time (NPT) and invisible lost time (ILT), and improve overall performance.

This paper demonstrates how one organization in China used a proven Knowledge Management process and award-winning KM software to build a knowledge base of expertise in the main onshore China oilfields. The authors will detail the process of knowledge extraction and the methods used to document this experiential knowledge, allowing its communication and collaborative re-use in Communities of Practice across the organization. As a first step in a long-term strategy, the authors will demonstrate through two case-studies how this knowledgebase has been re-used delivering savings to an international operator with a 25% reduction in drill bit consumption. Furthermore, the knowledge base was applied for a domestic operator, realizing drilling time of 38 days less than planned, eliminating unnecessary trips and increasing the overall percentage of productive on- bottom drilling time.
Wired Drill Pipe Telemetry Enables Real-Time Evaluation of Kick During Managed Pressure Drilling
Authors: Gravdal J. E. , Lorentzen R. J. , Time R. W.
Published: February 2011

Distributed pressure sensors along the drill string from wired drill pipe telemetry, combined with real-time analysis of the data at the rig, may give valuable information to the drilling control system and the decision makers when utilized properly. The step change in bandwidth, reliability and availability lead to better premises for developing new technology for more advanced drilling methodology.

In this paper, improved methodology for evaluation of kick in Managed Pressure Drilling (MPD) is presented based on this step change in availability of downhole pressure measurements. The objective of the presented methodology is to improve well control for MPD by faster and better diagnostics of flow interaction between well and formation and thereby reducing formation damage and non-productive time.

A representative North-Sea well is used as test case geometry and an advanced well flow model is used as a virtual well in computer simulations that provide the basis for the presented results. The proposed methodology is demonstrated to estimate the depth of influx zones as well as the size and distribution of the kick. This will improve the handling of the influx incident, prevent the risk of hole stability problems and thereby reduce cost associated with non-productive time.
Integrated 3D Reservoir Model and Petrophysical Study to Optimize Field Development in Low Permeability Deltaic Reservoir, Badak Field-Indonesia
Authors: Gultom Luhut , Benito Jose , Negara I Made , Adi Ratno , Soenoro Amireno , Nikijuluw Robert , Benyamin _
Published: February 2011

The fluvial deltaic VICO's Reservoirs are located in the eastern part of Kutai Basin, Indonesia, being Badak one of their biggest and most prolific Fields that has been producing gas for more than 35 years.

Badak, the first gas field discovered in the Basin, presents the concentrations of hydrocarbon in fluvial sediments, mainly in channels and bars deposits. These bodies are distributed through a vertical interval of thousands feet over various areas of the structure. At present, we face the challenge of developing the remaining gas reserves in these low permeability deep reservoirs. These reservoirs locally known as G and H levels are at depths between 11,000ft to 13,000ft.

During last couples of years considerable efforts have been done on developing fluvial facies model based on sedimentary environment and core data. The key factor, for better understanding the potential areas was an integrated 3D Model including also a detailed petrophysical analysis.

Based on core data cut-off values of porosity, permeability and water saturation were calculated and used for selection of the best well candidates, with the higher flow rates. The same cut-off values were applied in the 3D model in order to identify and characterize the main productive areas with high storage and flow capacity. The 3D model helped to understand the areal and vertical distribution of these petrophysical properties as well as porosity and water saturation.

As a result, confident locations for development of these low permeability reservoirs can be presented in order to increase the current recovery factor. Right applications of a reliable 3D model allows to identify of best areas and potential reservoir characteristics from limited quantity of data, obtainable from conventional cores and well logs to maximize the success of the project. Drilling in these reservoirs already contributed with 30 MMCFD of gas equivalent to 30% of field production.
Less Footprints in the Snow for Salym Field in Western Siberia
Authors: Cramer Ron , Mabian Andrew , Tulalian Robert
Published: February 2011

Salym Petroleum Development N.V. (SPD) is a Joint Venture operating and developing the Salym group of oilfields in Western Siberia. The fields are artificially lifted, predominantly using variable speed drive ESP's for some 330 wells (Q1 2010). Pump controllers and well head instrumentation has been tied-into a SCADA/Historian system. The basic control system is being enhanced by progressively installing Shell's integrated Smart Fields* capability based on the combination of FieldWare* suite of real time software applications (for real time monitoring, surveillance and control), electronically linked to offline Integrated Production System Models and the Hydrocarbon Accounting System. In this application FieldWare consists of four modules:

- Production Universe - real time oil, gas and water flows for all of the wells virtual flow measurement and for real time monitoring of ESP operating downhole parameters; - ESP - real time pump efficiency curves, reports, surveillance and remote control complemented by Mikon echometer fluid level measurement; - EOR – water injection optimization and real time water flows from source to injection, including real time monitoring of surface vessels levels, surface pumps and wells injection pressures and rates; - WellTest – well test optimization, enabling real time well test measurements screening, troubleshooting and automatic transfer of test data to the hydrocarbon accounting system.

The purpose of this paper is to describe/quantify Smart Fields benefits seen so-far in terms of less operator travel and hazard exposure, reduced ESP interrupts, more stable operations and faster re-starts. Benefits quantification is facilitated by meaningful comparison of automated and yet-to-be automated parts of the field, including impact from the deployment of Smart field Technologies in Salym fields.
Integrated Study for Field Development Challenge of a Brown Field with Seven Stacked Reservoirs
Authors: Kasap Ekrem , Qassabi Dawood , Lukmanov Rinat , Busaidy Rashid , Zarafi Ahmed
Published: February 2011

A brown field consisting of NE and SW accumulations has stacked six clastic and one carbonate reservoirs with fluid contacts per reservoir per accumulation. Depositional environment changes from shallow marine at the bottom to deltaic lacustrine at the top. Average rock properties and connectivity deteriorate from bottom to top.

Borehole rugosity and low resistivity contrast between hydrocarbon and water bearing intervals made petrophysical evaluations difficult that may have led to STOIIP overestimations. Production allocations for commingled horizons were not carfully done. The tests in some wells have suffered from packer leak and/or flow behind the casing. These sealing issues have drastically increased uncertainty in aquifer support for upper reservoirs and in oil production for lower reservoirs.

An integrated study with static and dynamic models was conducted to minimize uncertainties, risks and to optimize field development options. Well logs, and seismic, production, pressure, core, and PVT data in addition to well events are all incorporated into the models. Several IFT measurements were obtained at the start of the study and the results greatly reduced uncertainty in the height of capillary transition zones defined through 4 poro-perm and 5 capillary pressure models.

Multiple static model realisations were constructed based on sequence stratigraphic correlations, facies geometries, porosity distributions and analogue depositional systems. These realizations were input to dynamic models to establish Base, High and Low cases with historically possible range of uncertainty and risks for the field development options.

In conclusion, uncertainties were reduced from 120% to 10% after modeling and history matching identified active and passive STOIIP. Uncertainties in past production allocations were minimized via model well bore communications. Unconstrained development options lead to the optimum number of wells. After including drilling and surface facility costs, economics screening indicated that infill-drilling for the north-east and infill drilling supported with dump flooding for the south-west were the best options.

The study is completed in 2008 and the resultant plan has been being implemented in phases. Phase I involved one NE producer in 2009 and one SW water injector in 2010. Producer W-12 was a success and has been producing with an initial rate that was three times the discounted expectation rate due probably to 5m shallower structure and twice thicker bulk thickness and better permeability.
Transient Testing of CBM Wells
Authors: Stewart George
Published: February 2011

A review of coal bed methane (CBM) drill stem tests (DST) in Queensland has shown that complex reservoir behavior is common. In particular radial composite or multiple boundary effects have been diagnosed on log-log derivative plots. In this paper the treatment of stress dependent permeability and porosity (SDPP) in pressure transient testing and production forecasting is addressed. The application of a pseudopressure transform, which is the traditional method for tackling the problem, is described. The SDPP pseudopressure method presumes that the rock mechanics model is already known. In this study an alternative procedure termed pseudo model is proposed where the rock mechanics parameters can be determined by the nonlinear regression facility available in well test software. The application of this methodology is illustrated by a field example of an injection falloff from the US. One of the main effects of stress dependent permeability is a magnification of the effect of mechanical skin from formation damage and the origin of high total skin in CBM wells is attributed to this mechanism. Gas block due to the pressure falling below the critical desorption pressure is also a problem and typical gas-water relative permeability curves are used to assess this effect.
Evaluation of Mechanical Performance and Stress-Corrosion-Cracking Resistance of Post Expanded Carbon Steel and CRA Casing Grades
Authors: Bufalini A. , Morana R. , Nice P. I. , Nasvik H. , Kjørholt H. , Bailey B. M. , Adam M. K. , Jiral D. G. , Ross R. C. , Smith R. C , Ueda M. , Ohe T.
Published: February 2011

While expandable tubular technology significantly increased traction within the oil&gas industry in the last few years, materials behavior knowledge for expandable casing has not progress sufficiently. This is due to the lack of a diffused definition of the most appropriate procedures to verify post-expansion material performance and to the difficulties in performing investigation activity. These investigations rely on post-expanded material, which is costly and time-consuming to obtain, especially for the range of very large plastic deformations applicable to Monobore applications.

Consequently, an extensive testing program was started by Statoil to define an appropriate testing procedure for the evaluation of material performance after expansion and to characterize candidate materials. This paper presents the testing methodologies developed and the results obtained for several carbon steel grades and CRAs. These evaluations included tests of the mechanical performance and the resistance to aggressive environments.

The assessment of mechanical performance was carried out through several conventional and innovative tests and evaluation activities. Conventional tests included tensile tests in longitudinal and transverse direction, at room and elevated temperature, impact tests and residual stress evaluation. Collapse tests were performed on expanded pipes. Novel methods with optical strain measurements were adopted for improved tensile tests. Finite Element Analysis of the expansion process was also used to further investigate post-expansion mechanical performance. The resistance to stress corrosion cracking or sulphide stress corrosion was evaluated by means of FPB and C-ring tests. Carbon grades were tested in a mild sour environment while CRAs were tested in aggressive environments representative of possible field conditions. All experimental tests were carried out on materials before and after expansion. The effect of strain aging was also evaluated for carbon steel grades applying a defined aging cycle to expanded material.

The experimental methods adopted are described and discussed. The test results highlighted the main mechanical parameters to be considered and allowed ranking the different materials tested. At least one carbon steel grade and one CRA possess adequate mechanical and environmental performance even after 30% expansion. The test methodology adopted was therefore considered adequate for the aimed purpose.
Saving 70% Rig Completion Time in 13 Multizone Wells with Single Trip Multizone System in Mahakam Delta Offshore Indonesia
Authors: Suryanada Siswara , Wahyudhi Fransiskus , Garcia Euro , Landry Jed , Li Chunming , Hansen Cody , Daulton Dan
Published: February 2011

Reducing recurrent pipe trips offer significant time savings easily translating directly into improved well and/or project economic benefit. Utilizing a reliable multizone single trip method that reduces additional pipe trips compared to performing conventional stacked cased-hole Frac-Pack (FP) or High Rate Water Packs (HRWP) has a major impact on the overall completion costs associated with reservoirs containing multiple completion intervals. This multi-zone single trip system improves operational performance and stimulation effectiveness by incorporating an innovative service tool sealing mechanism with complete independent zonal isolation for each treatment interval. Additionally a selective zonal opening/closing tool offers an added degree of well performance control. This paper provides a summary of multizone single trip system introduction and utilization beginning in 2007 to Bekapai and Sisi Nubi field projects in Mahakam Delta offshore Indonesia for sand control in mutlilayer reservoirs.

To date, a total of 74 zones with FP/HRWP's on 16 wells have been successfully installed. An average of 5.3 days completion installation time has been achieved on 13 wells with 3-6 zones at an average depth of 12,000 ft (3,657 m). This compares to a completion installation time of 20 days per typical 5 zone stacked FP/HRWP well. As a result of efficiencies gained utilizing multizone completion technology greater than 70% rig time reduction has been achieved with $US 30 million dollars savings on the project thus far. This paper will also present lessons learned, application concerns when considering multizone single trip as a completion option and challenges going forward to improve implementation of multizone completion technology.
Thirty Years of Gas Shale Fracturing: What Have We Learned?
Authors: King George E.
Published: February 2011

Although high gas flow rates from shales are a relatively recent phenomenon, the knowledge bases of shale-specific well completions, fracturing and shale well operations have actually been growing for more than three decades and shale gas production reaches back almost one hundred ninety years. During the last decade of gas shale development, projected recovery of shale gas-in-place has increased from about 2% to estimates of about 50%; mainly through the development and adaptation of technologies to fit shale gas developments. Adapting technologies, including multi-stage fracturing of horizontal wells, slickwater fluids with minimum viscosity and simultaneous fracturing, have evolved to increase formation-face contact of the fracture system into the range of 9.2 million m2 (100 million ft2) in a very localized area of the reservoir by opening natural fractures. These technologies have made possible development of enormous gas reserves that were completely unavailable only a few years ago. Current and next generation technologies promise even more energy availability with advances in hybrid fracs, fracture complexity, fracture flow stability and methods of re-using water used in fracturing. This work surveyed over 350 shale completion, fracturing and operations publications, linking geosciences and engineering information together to relay learnings that will identify both intriguing information on selective opening and stabilizing of micro-fracture systems within the shales and new fields of endeavor needed to achieve the next level of shale development advancement.
Real Time Production Surveillance and Optimization Solution Implementation in an Offshore Brownfield in Malaysia
Authors: Wong Lee Hin , Grigorescu Ramona , Whitney Patricio , Arifin Azahari Mohd , Midun Romionson , Salim Muzahidin Muhamed
Published: February 2011

Gas lift optimization and design has traditionally used single-string analysis to perform optimization. This required time consuming exercises and lengthy processes that never achieved the global reach of field constraints management. In a dynamic brown field where field interruptions and process upsets are common, response time is a key performance indicator. These challenges were effectively overcame by introducing a Real Time Production Surveillance and Optimization system capable to perform dual string gas lift optimization field-wide and in real-time.

The implementation was the first Real Time Production Surveillance and Optimization system in the country. The system links up real-time operational data historian system and corporate production information management system (PIMS) and is coupled with the Well-Network suite of simulation tools to provide an integrated suite of production surveillance, diagnostic and optimization application modules that increase the efficiency of daily oil and gas operations activities.

The goal of this paper is to underscore the advantages and benefits that can be drawn from the utilization of Real Time Production Surveillance and Optimization System during the operational phase of production optimization process.