bluuebunny/crossref_metadata_2025 huggingface dataset:
EOR Potential in the Middle East: Current and Future Trends
Authors: Al-Mutairi Saad M. , Kokal Sunil L.
Published: September 2011

The majority of enhanced oil recovery (EOR) projects are being executed in the the U.S., Canada, Venezuela, Indonesia and China. The volume of oil produced by EOR methods increased considerably from 1.2 MMBD in 1990 to 2.5 MMBD in 2006 (Sandrea and Sandrea 2007). Current total world oil production from EOR is approaching 3 MMBD representing about 3.5% of the daily global oil production (Sandrea and Sandrea 2007). Thermal and CO2 methods are the major contributors to EOR production, followed by hydrocarbon gas injection and chemical EOR. Other more esoteric methods, e.g., microbial, have only been field tested, without any significant quantities being produced on a commercial scale. In recent years, the number of EOR projects has increased with escalating oil prices.

The number of EOR projects in the Middle East (ME) has also increased over the past decade. In some countries like Oman, there has been no choice but to implement EOR projects aggressively due to dwindling "easy oil." Other countries in the region have also started to think EOR, and are including them in their strategic short-, medium- and long-term development plans. Furthermore, there are many projects on the drawing board and appropriate screening studies and EOR pilots are being pursued region-wide. This paper reviews the current ME EOR projects from full-field development to field trials, including those on the drawing board. The option of advanced secondary recovery (ASR) — also known as improved oil recovery (IOR) — technologies before full-field deployment of EOR is also discussed. A case is made that they are a better first option before deployment of capital-intensive EOR projects. The ME’s general drive towards "ultimate" oil recovery — instead of immediate oil recovery — is highlighted in the context of EOR. Some of the enablers for EOR in the ME are also discussed in the paper. It highlights the opportunities and challenges of EOR specific to the region.
Success Story: Improving Reservoir Monitoring to Reduce Workover Cost & Increase Production in Offshore Marginal Oil Field
Authors: Pramboeidi Sri Khresno , Subiantoro Edy
Published: September 2011

Mengkapan is an offshore field in KPSA area. It is located between Sumatra, Padang Islands, Malacca Strait. Cumulative production from Mengkapan is 35 MMSTB since 1986 from 11 wells. The field, with recovery factor 50%, is considered as mature field. The wells produce commingles from several zones cross flow and production blocking occur due to difference pressure regime of each zone.

When the well is suffered from production declining, production spinner logging is run to monitor flow contribution and water cut from each zone. The result will be followed up with zonal isolation program by setting production packer at watered zone. Along the time, there will be no more zones to be isolated with packer but to abandon the well when the production declines again. Therefore, squeeze cementing is proposed.

C/O logging is performed prior to squeeze cementing. Cross flow is believed only occurs in high permeability interval and will not effect the reading. Remaining oil saturation up to 40% is found at the top of perforation and low permeability interval even the zone is predicted as watered zone from production spinner logging. Cement is squeezed and oil-bypassed interval is re-perforated. Squeeze cementing technique is also improved based on cross flow information from production spinner log.

EB well produced 9000 BFPD, 99.5% WC, 45 BOPD prior to squeeze cementing, now it produces 2000 BFPD, 94% WC, 120 BOPD. The budget for cementing was proposed up to USD 660,644.00 based on experience from other well and only 60% from the budget was used.

This paper explains improving reservoir monitoring helps to increase workover success ratio (reduce operation cost, and maximize gain) from concept, data gathering, until field application. The challenge is to change mindset from "no remaining oil" to "there is oil by-passed".
Study and Application of Anionic and Cationic Polymers Alternative Injection for In-depth Profile Control in Low Permeability Sandstone Reservoir
Authors: Caili Dai , Qing You , Xiqun Fan , Yuandong Peng , Guang Zhao , Ping Wang , Xiuying Wang , Fulin Zhao
Published: September 2011

In view of characteristics of low permeability sandstone reservoir and the aim of water control and oil increment, a mild water control technology referring to the alternative injection of anionic and cationic polymer for in-depth profile control in low permeability sandstone reservoir was proposed and developed when the oil wells were in high water cut stage. The adsorption equilibrium mass concentration of the cationic polymer is 1500 mg/l and the adsorption equilibrium time is about 8 hours, while the adsorption equilibrium mass concentration of the anionic polymer is 1000 mg/l and the adsorption equilibrium time is about 6 hours. The physical simulation experiment shows that anionic and cationic polymers alternative injection and prior injection of cationic polymer with high plugging capacity are better than the single polymer injection. The plugging capacity increases with the increase of injection rounds, the optimized injection round is no more than 3 times according to economic benefit. This technology is successfully applied in Shuangqian 6 well of Henan oilfield in June 2010. After treatment, the high permeability channel is effectively controlled, the water cut obviously decreased and the oil production increased, it is shown that this technology is a reliable and feasible technology and worthy to be widely applied in low permeability sandstone reservoir.
Evaluation of New Well Configurations for SAGD in Athabasca McMurray Formation
Authors: Tavallali M. , Maini B. , Harding T.
Published: September 2011

The Athabasca oil sands deposit is the largest oil sands deposit in Alberta-Canada which contains about 1.7 trillion barrels (270×109 m3) of bitumen in-place. In the Athabasca oil sand, most of the bitumen deposits are found within a single contiguous reservoir, the lower cretaceous McMurray Formation.

Since mid 1980’s, SAGD process feasibility has been field tested in many successful pilots and subsequently through several commercial projects in Athabasca-McMurray Formation. However, SAGD remains very energy intensive, extremely sensitive to geological and operational conditions, and an expensive oil recovery mechanism. Over the 20 years of SAGD experience in Athabasca, the only well configuration that has been field tested is the standard 1:1 configuration which has a horizontal injector lying approximately 5 meters above a horizontal producer.

This study examines the impact of using several modified well configurations for SAGD in the McMurray Formation in Athabasca in order to improve process performance. The technical feasibility of applying each arrangement was evaluated through sensitivity analysis. Numerical modeling was carried out using a commercial fully implicit thermal reservoir simulator; Computer Modeling Group (CMG) STARS 2009.13. The wellbore modeling was utilized to account for frictional pressure drop and heat losses along the wellbore. The reservoir properties were selected in order to accurately represent of the McMurray Formation in Athabasca.

The new well configurations provide operational and economical enhancement to the SAGD process over the standard well configuration in Athabasca area. The SAGD process response to different reservoir parameters of the McMurray Formation, such as mobile water saturation and reservoir heterogeneity in the form of bioturbated shale, has been investigated for the most promising of the new well configurations.
The Use of Downhole Temperature Data in Gas-Oil Ratio Estimation and Reservoir Management
Authors: Deucher R. H. , Gomes R. M. , Aniceto P. H. , de Souza C. N. , de Assis J. P.
Published: September 2011

In Campos Basin, deepwater offshore Brazil, permanent downhole gauges are used to record pressure and temperature. Pressure data are used extensively in well analysis, but temperature data have seen little use. Production data indicate that downhole temperature changes as a function of flowrate, pressure and fraction of fluids. A strong relationship was observed between flowing temperature and gas-oil ratio (GOR), caused by cooling upon expansion. It has also been observed that temperature data can be used to detect scale occurrence, aiding reservoir management. This paper proposes a methodology based on a semi-empirical equation that makes use of downhole temperature data to estimate GOR. The energy balance applied to the wellbore was simplified to generate an equation suitable to use with easily obtainable field data. The resulting equation has two unknown parameters, which are obtained by adjusting the model to field data. The inputs used to calibrate the model are GOR, oil flowrate, watercut and downhole temperature. The use of this methodology to three horizontal wells will be presented. For well C, the mean error obtained while estimating the GOR measured at the tests was 6.6%. In well B, the mean error was 11%. Well A has passed through a wide range of liquid flowrates, and over the 150 production tests that were performed before water breakthrough, the model was able to estimate the GOR with a mean error of 5.4%. However, after water breakthrough it could not reproduce the measured data accurately. In Campos Basin, accurate GOR measures are difficult to obtain, particularly after gas-lift start-up, because gas flowrate measurement is unreliable and test separators are often unavailable. Using this methodology, it is possible to obtain estimates of the GOR, which is desirable for an improved definition of the waterflood strategy and as a refined input for material balance in specific regions of the reservoir.
Experimental and Simulation Analysis of CO2 Storage in Tight and Fractured Sandstone under Different Stress Conditions
Authors: Farokhpoor R. , Baghbanbashi T. , Torsæter O. , Lindeberg E. , Mørk A.
Published: September 2011

Sequestration of carbon dioxide in a saline aquifer into shallow marine formation of Jurassic sandstones in Svalbard has been studied on unfractured cores and by using a simplified set of geological boundary conditions. In this paper, the feasibility of storing CO2 in a fracture and matrix system in a low permeable formation is studied by performing a series of laboratory experiments under different stress conditions. Laboratory core flooding experiments were conducted on two alternative fractured and unfractured cores. Water and nitrogen were injected into brine saturated cores at the reservoir conditions. The result shows that core plugs are very tight and the liquid permeability even for fractured core is less than 1 millidarcy. Under increased acting stress from 10 to 180 bar, the effective permeability of fractured core is reduced by 73 percent and fluid flow occurs through both fracture and matrix.

A conceptual, generic and simple 3D numerical model using commercial reservoir simulation software and available petrophysical data was used to study the CO2 injection through fracture at different overburden pressure. The effect of different overburden pressures were applied by using respective permeabilities in simulation model. Mean pressure along the cores was used to match simulation predictions with experiments results. The result shows that even though the system is water-wet, and matrix has a very high capillary pressure, CO2 flows through both fracture and matrix. The amount of CO2 that flows through the fracture is high and is reduced by increasing overburden pressure. The quantity of dissolved CO2 in brine phase reduces by decreasing overburden pressure and increasing permeability. The faster the CO2 is flowing through the fracture less time is available for CO2 to trap as residual phase and dissolve in brine. In dipping fractured saline aquifer, CO2 plume movement in updip direction is accelerated by decreased overburden pressure and increased permeability.
Integrated Drilling and Completion Data Workflow into a Strategic Data Management Solution: An Implementation Case Study from Cairn Energy India
Authors: Peytchev Peter , Thummar Dinesh , Singhal Rohit , Rosland Habil Akram , Tracy Simon
Published: September 2011

In 2008, Cairn Energy India, Ltd. (CEIL) recognized the importance of tackling unstructured data across the drilling and petroleum engineering group, where significant use of a proper workflow and a state-of-the-art data management application system have been promoted within the organization. The project rollout was aimed to achieve absolute integration of drilling and completion information into one centralized database system.

Over the last 10 years, the drilling and well services group has used the knowledge management system to achieve targeted maturity involving the conversion of a large volume of data into a reliable, yet simple, synchronized and structured data form. Collaboration between departments and vendor's application was needed for the CEIL process to remain effective following the company's aggressive growth.

This system was initially designed to generate schematics, reports, and queries. A specific workflow and process culture was required to ensure that all critical data, including operation-related information, are being captured meticulously during the lifecycle of a well.

Factual integration between the drilling and completion system was only possible after combining the thousands of reports into a centralized data management system. CEIL initiated the data management project to achieve reliable and accessible information across this domain, thus improving the group's productivity and operational efficiency.

This integration further facilitated the common access point for engineering personnel. In addition, it minimized the data entry workflow and effective use of decisive historical data. Data, once recorded, can be used by multiple applications intended for engineering, well-planning analysis, and operational monitoring. This integration has improved data quality and facilitated timely and cost-effective decision making.

This paper explains the methodology, strategy, and technology implemented in the data management project.
A Novel Technique for Monitoring Hydrate Safety Margin
Authors: Yang Jinhai , Chapoy Antonin , Mazloum Saeid , Tohidi Bahman
Published: September 2011

A novel technique has been developed for optimizing hydrate inhibitor dose rates by monitoring the actual hydrate safety margin. The technique is based on measuring acoustic velocity and electrical conductivity in an aqueous sample taken from the pipeline/separator. The developed system then determines salt and organic inhibitor concentration (e.g., methanol, mono ethylene glycol, kinetic hydrate inhibitors, etc). In the case of thermodynamic inhibitors the information is then fed to a thermodynamic model determining the hydrate stability zone. Superimposing the pipeline operating conditions (e.g., P&T profile) the developed system can determine the hydrate safety margin. The system can provide warning if the operating conditions is inside the hydrate stability zone or too much inhibitor is being injected.

The technique can be used in optimizing inhibitor injection rates, reducing the impact on the environment and operational costs. It can also improve the production system reliability by constant monitoring hydrate safety margin and protecting the system against pump malfunction and/or changes in process variables (e.g., water cut).

The above technique has been developed through a joint industry project and its performance has been intensively evaluated using the synthetic samples and real produced water samples by the authors, the project sponsors and field trials. The results demonstrate that this system can be used for different inhibitor systems including methanol-salt, mono ethylene glycol-salt, and kinetic hydrate inhibitor-salt systems with good accuracy.

The developed system can have a major impact on reducing the inhibitor injection rates, reducing environmental impact, and improving the reliability of production systems against risks associated with hydrate formation. The developed system can be lab based, mobile unit or on-line with near real time taking samples from live pipelines/separators.
Automatic Production and Seismic History Matching by Updating Locally and by Geological Environment in the Nelson Field
Authors: Kazemi Alireza , Stephen Karl D.
Published: September 2011

It is becoming common to use automatic or assisted techniques for history matching of oil and gas reservoirs. These techniques are complicated by the need to update the properties of the model that are linked to the geological representation of the reservoir but also affect the misfit between observations and prediction. In this work we compare updating of regional properties for the former while updating local properties to satisfy the latter.

We apply an automatic history matching approach to the Nelson field, a channelized turbidite reservoir, in order to better match the production rates of oil and water by well. We also integrate time lapse seismic data and we compare the result with production history matching output. We control the shale distribution within and between the major channel complexes by updating on the basis of geological environment variables which are regionally distributed. We compare this approach with more local updating by using pilot points with Kriginig.

By updating the reservoir properties by environment variables we reduce the total production history match misfit by 22% for six years of data. We also improve the forecast of a further three years by 20%. By updating locally after by environment, this improvement is 60% and 30% in the matching and forecasting periods respectively. By integrating time lapse seismic data in history matching to update by environment, the production misfit is reduced by an equivalent amount while forecasting is improved by 19%. Seismically we reduce the misfit by 7%.

Appropriate updating of the reservoir model is very important for reservoir management to reduce risk in development and to select appropriate models for forecasting. By updating the reservoir based on honouring the geological information or by using the geostatistical tools we can obtain a better representative of the reservoir with stronger prediction capability.
On the Right Road to High Efficiency and High Speed Recovery: The Experience of Development the Biggest Reservoir in Huizhou Field in South China Sea
Authors: Li Li , Zhang Wei , Qin Feng , Dai Zong , Dai Ling , Shui Min
Published: September 2011

This paper introduced the special development strategy and new technologies used to reach ‘high efficient, high speed’ recovery for offshore H filed, which located at 16/08 block of H fields group in the Pearl River Mouth Basin. As the biggest single lithology reservoir in South China Sea, K22 consisted 80% of the field OOIP. Great challenge was faced when the reservoir was discoverd at the year 1991, for the OOIP of the reservoir thought to be marginal and water depth of this field is more than 110m. Most of reservoir in the Pearl River Mouth Basin belongs to the low-relief anticline structure, while K22 is the first lithology reservoir found in South China Sea. Water flooding was thought to be the first choice for complicated heterogeneous and insufficient water drive energy formation. However, by optimizing well placement and installing ESP, a less but high-yield wells pattern was eventually applied.

After 15 years’ development, the OOIP of K22 is three times larger than original ODP. Current well performance and simulation study indicated the ultimate recovery would reach to 71.5%. The annual recovery factor was more than 10% at its peak year, corresponding to 55000 barrels per day with only 11 producers. The experience of successful development of K22 reservoir is a good story of ‘high efficient, high speed’ development strategy of offshore oil field. On one hand, the anti-rhythm reservoir characterized by good permeability and sufficient natural water energy guaranteed a high recovery factor; on the other hand, the integration of seismic data, single reservoir producing strategy, reservoir management and pay zone protection also play a great role in the process of oil field development.

In OOIP scale, speed of recovery and depletion rate, K22 are second to none among all fields in South China Sea, which has a significant reference value for the development of offshore fields. The technologies proved to be successful in K22, including seismic data frequency extension, the cost-effective streamline simulation and under-balanced perforation have been widely used in the industry.
Hole Cleaning Optimization in Horizontal Wells, a New Method to Compensate Negative Hole Inclination Effects
Authors: Malekzadeh N.. , Mohammadsalehi M..
Published: September 2011

With increasing measured depths and horizontal displacements in extended-reach (ERD) wells, good hole cleaning and cuttings removal remains a major challenge. Poor hole cleaning may result in lost circulation, hinder the casing or liner to be run into its selected position, excessive over pull on trips, high rotary torque, excessive equivalent circulation density, formation break down, slow rate of penetration, excessive bit wearing and pipe sticking. There are methods and models have been introduced to find the minimum flow rate required to remove the cuttings from the well. Larsen's model that can be used to find this flow rate from 55 to 90 degrees of hole inclination. Another one is Moore's correlation that is used to find the slip velocity of the cuttings in vertical wells.

This paper represents a new approach to achieve both optimized hole cleaning and flow rate, as a result of precise manipulations and redesigning of drilling mud rheological parameters, which have been elaborately explained in this paper. Calculations performed by computerized iterations via simulation software, which is developed based on theoretical concepts. Furthermore, Comparisons between calculated data and measured field data have been made. This method is valuable for prediction and calculation of the optimum flow rate for cuttings removal for all range of inclination, namely from 0 to 90 degrees and for providing guidance in further evaluations of this problem as well.

Data form a horizontal well YS5 which is drilled in Yort-e-Sha field in Iran is used to demonstrate the application of this method. As the significant outcomes, When the results of optimization applied, good hole cleaning condition achieved and negative effects of excessive flow rate such as drilling mud loss and drag were minimized.
Analyzing Dynamic Reservoir Behavior and Connectivity by Means of Formation Pressure While Drilling Technology
Authors: Salim D.. , Freitas E.. , Oliveira J.. , Lozada O.. , Canas J..
Published: September 2011

An extensive drilling campaign was done for the purpose of reservoir appraisal of an offshore Brazilian field that included complex deviated pilot wells. One of the objectives of this campaign was to provide detailed reservoir pressure information to determine fundamental reservoir properties. In order to optimize the data collection, it was necessary to acquire pressure measurements and also to transmit real time to validate test responses. Due to the complexity of well trajectories, the solution for executing pressure tests consisted of using Formation Pressure While Drilling technology.

The operation was carried out in five pilot wells providing critical results. The first result was the detection of non-linear reservoir depletions. Pressure tests also identified change of fluid phase in a black oil reservoir containing a gas cap. By comparing the fluid phase and gradient from early exploration wells, it was evident that the free gas was not originally present. This multiphase behavior reinforces the second result: confirmation of the dynamic process that reservoir fluids are undergoing. Moreover, different degrees of pressure depletions were observed in locations up to 1.5 km distant from producer well within same connected reservoir proving third outcome: the long lateral connectivity of reservoir sands. Another important outcome is that the actual bubble pressure is higher in magnitude and the current pressure depletion had fallen below it. The final outstanding result was the potential increase of oil reserves where pressure values identified unexpected sand channels with no drainage or very small depletions. The results of this pressure measurements analysis reinforced the need to optimize the potential capacity of oil recovery through acceleration of drilling injection wells for pressure maintenance.
Implementation of Customized Algorithms Extends Downhole Flowmeter Applications in Two-Phase Oil-Gas Flow: A Subsea North Sea Case Study
Authors: Kiryushkina T.. , Sikandar A.. , Figueroa M.. , Vasper A.. , Balster E.. , Eck J..
Published: September 2011

The Chestnut field is located in Block 22/2a in the central North Sea. The field, with water depths to 120 m, is approximately 180 km east of Aberdeen, Scotland. Chestnut was first commercially produced in September 2008 by Centrica Energy (formerly Venture Petroleum) using two subsea wells (a horizontal oil producer and a water injection well) tied into a floating production, storage, and offloading (FPSO) vessel. Water injection was required almost immediately because the oil was saturated. A second oil producing well was spudded in September 2008, targeting the South Chestnut field. This well, 22/2a-16Y, was tied into the same flowline and riser as the existing oil producer.

A venturi-type downhole flowmeter was installed in well 22/2a-16Y to obtain continuous pressure, temperature, and flow rate measurements. The production from the other well could then be calculated by subtracting the venturi flowmeter measurements from the total rate measurements made at the FPSO.

Venturi-type downhole flowmeters are, strictly speaking, only applicable in liquid environments because the Bernoulli principle is valid only for single-phase flow and is tenable only in low-slip liquid-liquid flow regimes, such as in the concurrent flow of oil and water at high velocities. Because the Chestnut oil is saturated, it was known that free gas would be seen at the intake of the venturi because the flowing pressure would, by definition, be below the bubblepoint.

To address the challenges caused by two-phase flow through the flowmeter, a workflow was developed that would first assess the quantity and affect of the free gas in the venturi device. The workflow was then developed to increase the accuracy of the flowmeter in the two-phase oil-gas flowing conditions. The enhanced flow calculations were then validated by using FPSO test separator data when only the flowmeter-equipped well was producing. The enhanced model improved the accuracy of the liquid-rate predictions across various rates from initial discrepancies of 40% to 190%, to less than 5%, allowing Centrica Energy to achieve its well- and reservoir-monitoring objectives.

The use of venturi-type flowmeters has traditionally been limited to applications in which only liquid is flowing through the meter. This present case study shows that customized workflows can improve the accuracy of the venturi flowmeter measurements in multiphase environments, making these downhole flowmeters a cost effective alternative to true multiphase meters for certain applications.
Application of Hybrid Artificial Lift to Produce Multizone with High GOR, Contrast PI and Contrast Water Cut
Authors: Matondang A. N. , Ibnu A.. , Subiantoro E..
Published: September 2011

N-5 well is located on XN offshore platform with ESP completion and was produced with very high water cut. The well was completed and perforated in A, B, C and F zones with straddle packer to isolate E zone. One time the water cut was suddenly decreased. The analysis of well completion suspected that there's leaking on Straddle packer covering E zone which the booked recoverable reserves 2 MMSTB was not appraised yet. The previous N-5 production data from Dec-00 to Jan-01 reported that the E zone can't produce continuously due to excessive gas which caused ESP shut down by gas lock problem.

Referring to the DST result of the offset well (N-1 well), found that the E zone have a good oil bearing, and good reservoir properties (Porosity, Permeability, Swi). Evaluation was made to identify any possibility to produce E zone with customized completion design. Combination of gas lift valve, ESP gas separator, VSD and selective completion was made and successfully anticipate gas lock problem on ESP. The gas can be separated from ESP, then release it through gas lift mandrel above the ESP.

In the initial condition after workover job, N-5 well was produced from E zone with very low rate and caused ESP shut down due to low influx. By taking advantage from selective completion we could optimize production through "Switching Method".

Optimization completion design by using combination of gas lift valve, ESP gas separator, VSD, and selective completion resulting continuous production from E zone, reducing 99% water production, increasing oil production of N-5 well, and move reserve status of E zones from 1P to 2P.
Knowledge Transfer and Introduction of a Remote Operations Model Developed over a Decade - From the North Sea to Brazil
Authors: Saeverhagen E.. , Thompson K.. , Dagestad J.. , Tardio M.. , Bersaas K.. , Grøvik L
Published: September 2011

This paper will provide a description of the benefits of the remote operations alternatives developed over a decade in the North Sea. Substantial support from Hydro/Statoil, starting in 1999, with remote data monitoring, re-manning the rig site with remote support, and the transfer of rig-based work tasks to a remote operations centre has changed the way we operate today and will also influence how automation will be integrated in the future.

Reduction in personnel-on-board (POB) and alternative remote operational models implemented resulted in measurable reductions in cost and HS&E exposure. The paper will give a thorough description of how continuous high operational performance and efficiency gains to operations at different levels has been achieved and documented in the North Sea and translated to the Brazil environment.

Other key areas for discussion are: improved performance and reliability, decreased NPT, standardized work processes, 24/7 technical support, real-time drilling optimization, cross-training of personnel, real-time data processing, immediate access to experts.

Current remote operations models will continue to evolve by further integrating several classic service deliveries, like directional drilling, measurement and logging-while-drilling (MWD/LWD), mud logging, drilling fluids, wireline logging and other services and job functions. This integration will occur because automated advisory systems will be available, delivering advice based on a wider range of surface and downhole data as well as historical databases and best practices, replacing individual judgment and assumptions. This will significantly contribute to improved HS&E performance as well as risk mitigation.

Automated systems in close combination with new cross-trained functions in the operations centers and re-manning of rig sites with reduced POB therefore will become the next step in automation of the overall drilling process.
Long Term Positioning Technology for Deepwater Drilling Applications
Authors: Hanton S..
Published: September 2011

The discovery and progression towards development of increasingly deepwater fields in recent years has been obvious, as has the increase in technology developed to support the technological challenges associated with this.

Developments are becoming faster and more cost efficient, but this puts pressures on schedules with offshore SIMOPs becoming ever more commonplace, and vessel and rig operations more safety critical. Maintaining position is a key part of safe SIMOPs, with the vast majority of vessels now being equipped with DP systems for station keeping. These systems are technological wonders, but are completely dependent on the quality of data being provided to them from the various sensors. Surface positioning today is very much reliant on Global Navigation Satellite Systems (GNSS) of which GPS (Global Positioning System) is the current preeminent example.

Although often perceived as ever reliable, GNSS signals are vulnerable to interference with one major source being from charged particles in the earth's atmosphere. During periods of increased sunspot activity a charged stream of solar particles (the solar wind) interacting with the earth's ionosphere can create geomagnetic ‘storms’ which can affect all radio signals (including those used by GNSS) up to and including complete loss of signal. These effects are often referred to as scintillation, which is a rapid fluctuation in signal phase and amplitude.

Acoustic positioning solutions are therefore a critical component of the DP system, but historically seen as a poor relation to satellite positioning

The challenges associated with acoustic positioning systems, from technical and commercial aspects, along with a potential solution, will be explained and discussed over the next few pages.
The Quest for Drilling Optimization Improvement by Using Business Intelligence Methods
Authors: Thomson Ian J. , Vulgamore Dustin J.
Published: September 2011

In today's market, service and oil companies must invest heavily in research and development of new technologies to succeed in the increasingly demanding drilling environment. They must also implement the most appropriate drilling techniques and best practices to overcome the drilling and geological challenges to reach their targets more efficiently.

In an offshore drilling operation, understanding the main drilling challenges for each individual well is not always an easy task. Consequently, identifying opportunities for improvement is not always straightforward, and requires thorough drilling data gathering and analysis to provide more applicable solutions.

The use of knowledge management technology and processes to gather and analyze data to gain a better understanding of the main challenges in a particular application, combined with the design of solutions based on the findings, is commonly referred to as business intelligence.

This paper will present how a service company uses business intelligence methods to acquire relevant drilling data and import it into knowledge management systems prior to performing data analysis to benchmark performance and identify drilling hazards and opportunities for improvement.

Key drilling data obtained from select Gulf of Mexico wells from 2007 to 2009 were studied to determine, by statistical analysis, the most common sources of nonproductive time, which is the main reason for pulling out of the hole and the most common reason for out-of-specification runs. Understanding those factors is crucial for implementing appropriate corrective actions and developing new technology, along with planning and executing best drilling practices.
A Multistage Approach to IOR/EOR Screening and Potential Evaluation
Authors: Surguchev Leonid M. , Reich Eva-Maria , Berenblyum Roman , Shchipanov Anton
Published: September 2011

This paper presents an evaluation study and some latest advances in a multi-stage approach to selection of EOR strategies. The essence of a multi-stage approach is in combination of first-order screening based on ranges for critical oil parameters, statistical data from the world wide database, analytical modelling of IOR/EOR process and economic / risk evaluation.

Screening and analytical methods are often used for fast preliminary evaluations of various EOR scenarios. Advantages of this approach are its speed, relatively small amount of data necessary to estimate the recovery of a particular EOR technique and a dispersion free analytical solution. Simplified representation of the reservoir used in analytical simulation aids in understanding dominating effects and forces and may be used to verify numerical results. The approach is viable and practical when a large number of reservoirs are to be screened for EOR applicability or when a decision over a new asset with limited field data is to be made.

This paper presents new database and improvements in cluster analysis used for estimation of recovery factor. We present a new flexible methodology allowing adding or removing database entries followed up by re-clusterisation and finally cluster-analysis based evaluation of the recovery factor.

A new improved methodology to evaluate performance of the WAG injection is discussed. A three phase compositional path (based on realistic relative permeabilities and rock properties) for each simulation layer is used to determine residual oil saturation to WAG. This value is later on used in analytical evaluation of WAG performance.

Economical evaluation would be integrated into the tool allowing performing economical analysis based on the analytical production profiles calculated within the tool or external data. The economic evaluation may be carried out in "simplified" or "advanced" mode. Advanced mode allows more detalization in specifying costs, while simplified model allows for faster economical evaluation when in-depth economical evaluation is not possible.

Finally a case study of an actual reservoir is presented illustrating how the "EOR compass" could be used in real life situations. The field case presented illustrates screening a new asset as a gas injection candidate. The field in study was taken through a three stage technical evaluation looking at applicability of key development strategies, comparing to the available field cases in the world and finally performing a sensitivity study using an analytical layered model.
Reduction of Perforating Gunshock Loads
Authors: Baumann C.. , Bustillos E.. , Guerra J.. , William A.. , Williams H..
Published: September 2011

Thousands of well perforation jobs are executed successfully around the world each month; however, certain perforation jobs require special design considerations to minimize the risk of equipment damage due to perforating gunshock loads, such as bent tubing and unset packers. Perforating gunshock loads generate pressure waves in the completion fluid and stress waves in structural components. The magnitude, duration, and timing of these waves depend on job parameters that can be adjusted by the design engineer, such as type, length, and loading of guns, number of shock absorbers, distance from sump packer to bottom of guns, and distance from completion packer to top of guns. The sensitivity of peak loads and gunstring movement to key design parameters can be evaluated with a software tool specifically developed to predict well-perforation induced transient fluid-pressure waves and the ensuing structural loads. All relevant aspects of well perforating events are modeled, including gun carrier filling after firing, wellbore pressure waves and associated fluid movement, wellbore pressurization and depressurization by reservoir pressure, and the dynamics of all relevant gunstring components, including shock absorbers, tubing, and guns.

Existing fast-gauge pressure data from a large number of perforation jobs were used in previous jobs to verify that predictions made by using software simulation are sufficiently accurate, both in magnitude and time; thus, the transient pressure loading on well components is sufficiently accurate to predict the structural dynamics response and the associated gunstring loads. In this paper, we present case studies that show how key elements used for gunshock mitigation are simulated, and the sensitivity of peak loads and deformation to gunstring elements, such as shock absorbers, gun types and loading, tubing size and weight, and packer placement.

With this software, we evaluate the dependence or sensitivity of peak loads and gunstring movement to key design parameters, and when necessary, design changes are made to reduce potentially unsafe load conditions. The design verification and optimization methodology described in this paper reduces significantly the risk of nonproductive time and fishing operations. Key technologies described in this paper enabled the successful execution of many deepwater high-pressure (HP) perforation jobs, including Petrobras' Cascade and Chinook, the largest deepwater HP perforation jobs done to date in the Gulf of Mexico.
Expert System for the Optimal Design and Execution of Successful Completion Practices Using Artificial Bayesian Intelligence
Authors: Al-Yami A. S. , Schubert J.. , Beck G..
Published: September 2011

To the best of the authors' knowledge, there are no standard guidelines to help in the effective design of completion practices. Many completions have been analyzed in this project, resulting in the best practices, as outlined in this paper.

The objective of this paper is to propose a set of guidelines for the optimal completion design, by integrating current best practices through a decision-making system based on Artificial Bayesian Intelligence. Best completion practices collected from data, models, and experts' opinions, are integrated into a Bayesian Network BN to simulate likely scenarios of its use, that will honor efficient designs when dictated by varying well objectives, well types, temperatures, pressures, rock and fluid properties.

The described decision-making model follows a causal and uncertainty-based approach capable of simulating realistic conditions on the use of completion operations. For instance, the use of water swelling packer dictates the use of organic acids instead of HCl acids. However, rock type and well geometry affect our selection of treatment fluids. Another example is selection of sand control method based on rock properties. The paper also outlines best operational practices in fracturing, sand control, perforation, treatment and completion fluids, multilateral junction level selection and lateral completion. The paper also discusses in details special well completions. Completion experts' opinions were considered in building the model in this paper.

The outcome of this paper is a user-friendly tool, where one can easily find the specific subject of interest, and by the click of a button, get the related information you are seeking. Field cases will also be discussed to validate this work.
Using RESQML for Shared Earth Model Data Exchanges between Commercial Modelling Applications and In-House Developments, Demonstrated on Actual Subsurface Data
Authors: Morandini Francis , Michel Bruno , Verney Philippe , Rainaud Jean-Francois , Deny Laurent , Dulac Jean-Claude , Fitzpatrick Tony , Eastick Rob , Towery Lisa
Published: September 2011

After intense collaboration among operators, service companies, and software vendors (all members of an Energistics Special Interest Group (SIG)) Version 1.0 of the RESQML data exchange standard has been released. Prototypes implemented by both vendors and operators have been tested and have proved the efficiency of the concepts.

RESQML has been designed to support: Interaction with real-time production and drilling domains;Transfer of giga-cell reservoir simulation models, which are currently in use in some areas of the world, and with static reservoir models, which may be significantly larger;Loss-less data transfer for complex grids, especially for non-standard connectivity;Retention of the geologic and geophysical meta-data associated with 3D grids;Data exchange for flexible and iterative multi-vendor subsurface workflowsacross geology, geophysics and engineering.

A demonstration will illustrate how different components of a shared earth model can be exchanged between major commercial applications. Additionally, based on the Alwyn North Field dataset, a typical validation loop involving operator in-house and vendor applications will be demonstrated. The objective is to transfer in-house interpretation results (e.g., horizons and faults) as RESQML features to diverse structural, stratigraphic, and reservoir vendor applications, then re-import the RESQML features (modelled horizon and faults, reservoir grid geometry) obtained by these applications into the in-house application to ensure, at each step, an overall consistency with the original interpretation.
Development of Heavy Oil Offshore Lake Maracaibo Field Using Slug Gas Lift: A Case History
Authors: Ortiz-Volcan Jose Luis
Published: September 2011

During the 80's a novel artificial lift method called slug gas lift was developed in-house in Lagoven (former affiliate of PDVSA), by a group of production engineers and it was applied to develop the first commercial phase of Urdaneta Offshore Lake Maracaibo Field between 1982 to 1984 that reached up to 50000 barrels per day with an average production per vertical well of 350 barrels per day of a 12°API heavy oil from depths between 6000 to 7000 feet.

Continuous gas lifting when applied to high productivity heavy oil reservoirs generate production problems caused by foam formation. Intermittent gas lifting on the other hand presents limitations for reservoirs such as Urdaneta-01 because a high productivity reservoir is capable of filling the production tubing with fluids and requires lifting from depths below 7000 feet. Slug gas lift was developed as alternative to continuous and intermittent gas lifting to deal with heavy oil reservoirs such as Urdaneta 01. This reservoir was discovered in 1946 and commercial exploitation started in 1982. Petroleum initially in place was estimated in 12 billion barrels with initial reservoir pressure of 3500 Psig and average depth of 8000 feet.

By applying slug gas lift the operator (Lagoven) was able to minimize foam formation by limiting the dynamic contact of gas and heavy oil liquid phases. The slug gas lift system is designed to prevent admission of liquids while gas is being injected at high pressure into the tubing, so condition for foam formation is eliminated.

Up until now there has not been any publication in SPE about this experience. The author was part of the production engineering group in charge of the Urdaneta field development project in 1982 and he also participated in the development and application of the slug gas lift model, This paper reviews the basis of slug gas lift, range of application and how it was applied in Urdaneta Field using the results from the first year of evaluation of a group of wells that constituted the first field pilot test.

It is likely that some heavy oil reservoirs located offshore worldwide could be potential candidates for application of slug gas lift.