bluuebunny/crossref_metadata_2025_split huggingface dataset:
Extending the Life of Mature Oil Field by Converting Gas Wells into Oil Wells
Authors: Hadiaman F. , Wismayandi H. , Setyawan H. 
Published: February 2011

Abstract
The Handil field is a giant mature oil field in Indonesia. It has been producing since 1975 with current recovery factor for oil is 49% and gas is 57%. Cumulatively, oil had been produced around 855 MMstb and gas around 1.68 Tcf. Now, from this field, oil is being produced at 20,000 bopd, gas at 75 mmscfd and water at 130,000 bwpd. One of the feasible and economic ways to recover the remaining oil at this late stage of field production is by doing a Light Workover technique. This technique aims to change the well status without pulling out the existing completion. This technique is considered the optimum way to maintain the field production performance up to now. One of Light Workover technique is to do re-completion by inserting smaller completion inside existing completion. An innovative spool adapter was utilized to be able to run smaller completion and sit above existing wellhead. Hence, from three (3) depleted gas wells that were converted into oil wells, all wells are still producing and economically had been paid out the intervention cost.
This technique is considered applicable for a mature oil field where some gas wells had been depleted and oil layers are exist.
Multizone Single Trip (MST): Deepwater and Downward Recompletion Case Histories
Authors: Sanford J. R. , Flanagan E. J. , Bruton J. , Woomer J. , Prince J. C. , Landry J. M. , Hansen C. 
Published: February 2011

Abstract
Multizone single trip (MST) systems are currently being evaluated for deep water low tertiary (LT) trends1 where multiple sand control intervals are required. However, this technology can be implemented in other applications. This paper will review the use of this system in two case histories.
The first and primary case history, Mississippi Canyon (MC) 502 Well 2, was the first implementation of a multizone system in the deepwater Gulf of Mexico (GoM). MC 502 Well 2 was part of the Longhorn development, where four (4) different completion types were implemented in the same field, similar measured depth (MD) and pressure regime. A direct comparison of the completion techniques will detail the time savings associated with the MST system.
The second case history, West Delta (WD) 89 Well A-01, is an innovative solution to a downward recompletion using a MST system to isolate the previous completions. Without the MST technology, this well probably could not have been completed.
Based on the results of these case histories, MST completion techniques should be considered for all equivalent pressure multizone completions. Additionally, a MST system is a tool than can be utilized in more applications than high cost deepwater stacked completions.
Increasing the tools available to perform completion operations is always significant. The resulting savings associated with this technology, is in the multiple million dollar range. By proving up this technology, MST sytems will allow the LT trend to be developed more economically.
Key Criteria for a Successful Microseismic Project
Authors: Maxwell S. C. , Underhill B. , Bennett L. , Woerpel C. , Martinez A. 
Published: February 2011

Abstract
As microseismic monitoring expands, a wide variety of monitoring configurations have evolved including vertical, horizontal and deviated observation wells as well as surface and near-surface monitoring. All monitoring configurations have a common data quality indicator: signal-to-noise ratio (SNR) such that the higher the SNR the more accurate and confident the results. The key criteria for a successful microseismic project therefore primarily involve maximizing SNR. Data acquisition can be designed to optimize SNR by using low-noise equipment designed to record appropriate data quality, deployed as close as possible to the target zone. Sample rate should be tailored to the signal bandwidth, and the equipment should also have optimal directional response although for individual microseismic events both will be controlled by the data SNR. Finally, the position of the sensor array will control the fundamental location accuracy, although this will be commonly be a trade-off with SNR depending on logistical constraints of monitoring wellbore access. Recent processing techniques based on seismic migration methods, offer automated and repeatable processing with inherent signal conditioning which provided SNR improvement. Associated with the automated processing is the ability of realtime delivery of all the microseismic events for realtime stimulation decisions. A demonstration with an automatically processed dataset, illustrated the importance of filtering the events based on SNR. Low SNR events had higher location uncertainty, such that both the volume of the microseismic cloud and its aspect ratio were made anomalously large. An accurate microseismic image was produced by filtering out the low confidence, low SNR events. Beyond the geophysical processing aspects, it is equally important that the microseismic project be designed so that engineering value can be extracted by determining valuable fracture details or answering key questions.
Using Microseismic Source Parameters to Evaluate the Influence of Faults on Fracture Treatments - A Geophysical Approach to Interpretation
Authors: Downie R. C. , Kronenberger E. , Maxwell S. C. 
Published: February 2011

Abstract
Microseismic monitoring during hydraulic fracturing treatments has confirmed that hydraulic fractures are much more complex than might have been assumed even a few years ago, when conventional fracture models were considered adequate. Analysis of diagnostic pump-in tests and mining tunnels has shown that fracture complexity exists in both the near-wellbore and far-field regions of the fracture. Also, microseismic monitoring and interpretation have shown that even fractures initiated in the same wellbore during successive stages can have distinctly different characteristics.
Evaluating the effectiveness of hydraulic fracture treatments using microseismic events is challenging. The most common techniques attempt to correlate production with the dimensions of the microseismic clouds and volume estimates based on the density of microseismic events.
Geophysical interpretation has shown that microseismic activity recorded during fracturing treatments can sometimes be associated with existing geological structures such as faults. It is possible to examine the frequency of the microseismic event magnitudes during a fracturing treatment and determine if microseismic events are being produced by the failure of the existing rock fabric, or activation of existing geologic structural features, which might be detrimental to well performance. The resulting frequency-magnitude distributions can then be correlated to observed fracture geometries.
We show that it is possible to use microseismic magnitude to identify whether faults are influencing the observed dimensions of the microseismic event cloud. We also show that it is possible to use microseismic magnitude values to evaluate fracture behavior in real-time applications, allowing stimulation engineers to modify individual stage treatment designs as the specific situation dictates. The potential benefits to both stimulation cost and production results will also be discussed.
Stochastic Analysis of Resource Plays: Maximizing Portfolio Value and Mitigating Risks
Authors: Allan Paul D. 
Published: February 2011

Abstract
This paper outlines a method for applying stochastic representations of key macro-economic parameters and risks in evaluating the portfolio value of resource plays. Stochastic pricing, costs forecasts, and regulatory uncertainties are often neglected or improperly applied when evaluating what are typically considered to be ‘low risk’ resource opportunities. Portfolio allocation and project development timing may be critically dependent upon these macro-economic variables, particularly given the long production life and operationally intensive nature of many resource opportunities. The techniques described in this paper will allow corporate planners and E&P executives to better leverage their opportunity inventory and ensure resource play development plans are in alignment with stochastic pricing or other macro-economic forecasts. A model of a typical E&P portfolio with numerous resource plays will be used to demonstrate the basic methodologies and the insights made possible through application of these techniques. This will include analysis of leasing options, pilot project evaluation, development timing and pacing options, and portfolio balance under various macro-economic conditions. The characteristics of project level analysis will be contrasted to the decisions and insights made possible via a holistic portfolio based approach.
Enhancing Gas Production in Coal Bed Methane Formations With Zeta Potential Altering System
Authors: Kakadjian Sarkis , Garza Jose , Zamora Frank 
Published: February 2011

Abstract
This paper describes lab studies and field results on how a new Zeta Potential Altering System (ZPAS), utilized in fracturing treating fluids, improves gas rate production. Lab and field results show ZPAS minimizes proppant flow back and coal fines migration, enhances fluid load recovery, and inhibits calcium carbonate scale formation. The mechanism of this system based on an inner salt that modifies the Zeta Potential on particles such as frac sand and formation substrate, changing the charge towards neutral values and therefore enhancing particles agglomeration.
This paper also shows how the Zeta Potential Altering System has been applied in numerous coalbed methane wells which were treated by refracturing. The ZPAS has been run in borate cross-linked fluids and linear gel systems. Field results have been positive on wells treated, with less time to clean out frac sand, less flow back sand and coal fines, higher conductivity after load fluid recovery, and higher gas productivity after load fluid recovery and de-watering of CBM Zones. Production has increased up to 15 fold on individual wells with 3 to 20 months production history.
Modeling of Fluid Transfer from Shale Matrix to Fracture Network
Authors: Ozkan E. , Raghavan R. , Apaydin O. G. 
Published: February 2011

Abstract
The objective of this paper is to incorporate a more detailed description of flow in shale matrix to improve modeling of production from fractured shale-gas reservoirs. Currently, most modeling approaches for shale-gas and -oil production are based on the dominance of Darcy flow in both natural fractures and matrix. We improve the description of matrix flow by considering diffusive (Knudsen) flow in nanopores. In our dual-mechanism approach, when Darcy flow becomes insignificant due to nanodarcy matrix permeability, Knudsen flow takes over and contributes, substantially, to the transfer of fluids from matrix to fracture network. Furthermore, we consider stress-dependent permeability in the fracture network. Therefore, incorporating Darcy and diffusive flows in the matrix and stress-dependent permeability in the fractures, we develop a dual-mechanism dual-porosity naturally fractured reservoir formulation and derive a new transfer function for fractured shale-gas reservoirs. The dual-mechanism dualporosity formulation presented in this paper can be used for numerical or analytical modeling purposes. We use the new formulation of matrix to fracture fluid transfer with an analytical model and demonstrate the differences from the conventional formulation.
Knowledge Transfer via Education and Training Partnerships Among Global Universities, IOCs, and NOCs
Authors: Baughman Gary L. , Van Kirk Craig W. 
Published: February 2011

Abstract
The following paper summarizes the authors’ perspectives on establishing and maintaining a dynamic off-campus outreach program at a traditional university with geo-petro disciplines. Cited are the challenges to be faced as well as suggestions and recommendations for achieving success. Emphasis is placed on the importance of establishing partnerships among other universities, international oil companies, national oil companies, and when appropriate, governmental agencies.
Application of Different Stimulation Techniques, Multistage Proppant and Acid Fracturing Operations Offshore Congo
Authors: Rotondi M. , Pace G. , Malonga H. , Pounga F. , Batmaz T. , Ndoassal E. , Asibor E. , Sobernheim D. , Amare P. 
Published: February 2011

Abstract
This paper describes the successful combination of different stimulation techniques during the development phase of an offshore field in Congo. A total of four wells were drilled and completed during 2008-10. The target reservoir, the Sendji carbonates, has a total thickness of 150-170 vertical meters with an interlayer of ten meters. It is composed of silty-shaly dolomitic and quarzitic sandstone with interbeds of shale and sand grading to sandstone and silt with dolomitic cement characterized by very poor petrophysical properties. Laboratory testing with cuttings showed that formation is more than eighty percent soluble with fifteen percent hydrochloric acid. The typical well has an average azimuth and inclination of 60 and 350 degrees respectively, in the target reservoir. A good quality cementation job of the casing was required in order to ensure isolation from the aquifer. The well completions are both open and cased hole multistage fracturing completion systems. Selected zones of varying lengths were hydraulically fractured by using proppant / seawater-based borate crosslinker fluid or by using twenty percent delayed, viscoelastic and straight acid. Two wells were stimulated by means of proppant fracturing while the other two by acid fracturing. Due to upper / lower water zones with no bounding beds, it was important to define formation mechanical properties for fracturing designs in order to avoid fracturing into water bearing layers. A Mechanical Earth Model (MEM) was created by using sonic anisotropy measurements, modular dynamic test results, and other common electrical logging data together with drilling parameters. The detailed study of design methodology, different stimulation fluids and operation sequences are described. Particular attention will be given to the comparison of well responses to multi-stage proppant and acid fracturing techniques.
Use of Wellbore-Reservoir Coupled Dynamic Simulation to Evaluate the Cycling Capability of Liquid-Loaded Gas Wells
Authors: Hu Bin , Veeken Kees , Yusuf Rahel , Holmås Håvard 
Published: February 2011

Abstract
The regulated intermittent gas production by automated on/off of the wellhead choke, also called "well cycling", is often the only short-term option that the offshore operators can practice in order to prolong the well production life once they are loaded up by liquid. The field experiences show that many wells can be cycled for quite a long period, but some other wells may have no cycling capability at all. For the wells that can be cycled, the average production achieved by the cycling also depends on whether and how this process is controlled. These bring in a large uncertainty in predicting the field tail-end production.
This paper is therefore concerned with the numerical modeling and simulation of the regulated well cycling. As the process involves both wellbore and near-wellbore reservoir dynamics, an integrated modeling approach is adopted through coupling a transient well flow model to a near-wellbore reservoir model. The coupled model was successfully used to investigate the cycling potential of a 3-km deep vertical well that produces from a depleted cylindrical reservoir of 100 meters in thickness and 560 meters in radius.
The simulation results confirm that the selected well can be cycled for a long period only if the operator pro-actively starts the cycling before the well is loaded up by liquid. The simulation also shows that the average gas production for the selected well can be at least doubled compared with the meta-stable production rate resulting from leaving the choke permanently open, which confirms the advantage of well cycling.
The major observation in this paper may fundamentally change the offshore gas well operation strategy as that the operators may start well cycling once they foresee liquid loading is soon due to occur in their wells. Besides, the simulation procedure presented can provide advices on how to optimize the timing of the choke on/off operation to maximize the average production.
Breaking the Boundaries for Wireline Sand Removal
Authors: Karlsen Ole Eddie , Mathiassen Erling 
Published: February 2011

Abstract
A new application of wireline tractors in combination with wireline sand removal technology has been proven in the Norwegian Continental Sector. Statoil experienced problems with sand build up in one of their production wells and needed to gain knowledge weather it was sand production or mechanical issues that disturbed the well. When using traditional equipment only 2.5 dl of sand were removed, which provided no conclusions for the operator.
It was decided to use the wireline cleaner PST (Power Suction Tool) to determine what caused the decrease in production. The PST is a newly developed cleaning device that can be run on electric wireline, either with a wireline tractor or as a "stand alone" tool.
The PST removed 26 litres of sand after the second run, which corresponds to a full bailer chamber that was used on this particular job. The PST is capable of carrying up to 100 litres of sand in one run.The offshore operation was successfully completed and after three runs it was possible to conclude status on the actual well. In this case, the problem was identified and the operator received improved knowledge of the down hole conditions that made it safe to continue the production.
With this new technology, it has been proven that the PST is an effective solution to elucidate down hole sand problems. This new application for sand removal in completion hardware and other well bore obstructions offers a cost-efficient alternative technology to existing methods. The success of the cleaning operation is quite an achievement and has pushed the limits for what is possible to achieve on electric wireline.
This paper will examine the challenges and solution chosen in an operation of removal of sand on electric wireline.
Well Design Specificities for Shallow Gas Production of Tunu Field
Authors: Oumer S. , Taufiqurrachman H. , Perruchot M. P. , Yunus F. 
Published: February 2011

Abstract
Since the beginning of Tunu field development in the late 80’s, shallow gas hazard has always been considered the major operational risk during the surface drilling operation. During the last ten years, 5 shallow gas events were reported; all have been safely controlled (no injured personnel) and the main consequences were material loss and non productive time.
With the objective to reduce shallow gas reservoir crossing, a high resolution seismic survey was performed in 2005. The survey results have been used to early identify potential shallow gas hazards at planning stage by 1) checking the field history of the selected future platform area and 2) systematically reviewing the seismic data on a well by well basis. Despite of the above described mitigation measures it appears that during 2007/2008, amongst 88 wells drilled, 43 shallow gas reservoirs (thickness above 6m) have been crossed on Tunu field. This phenomenon is directly linked to the geological fluvial deposit specificities of the Mahakam delta.
The shallow gas horizons (500-1200m TVD) became recently a source of interest for the geoscientists who mapped the gas in place yielding substantial reserves. After the potential has been confirmed, the drilling engineering studies started in order to design a well being able to produce shallow reservoirs. It is worth to remind that shallow gas drilling engineering is not a routine job…What kind of well architecture? Do we set a surface casing? Where do we set it? How will we manage the extremely low LOT at casing shoe? Which mud type has to be used? What will be the required mud density? How do we manage potential unconsolidated sand production....? So many questions looking for accurate technical answers in order to convert a hazard into a well.
In 2010, a specific development plan has been proposed and approved for constructing 17 shallow gas wells, showing highly encouraging production results to date.
Monitoring Reservoir Performance in Highly Prolific Deepwater Gulf of Mexico Gas Wells
Authors: Chu Wei-Chun , Gray W. M. 
Published: February 2011

Abstract
The deepwater Gulf of Mexico contains numerous gas fields with highly prolific wells that have the potential to deliver exceptional profitability to an Operator. This paper presents a case history of the utilization of real-time well surveillance data to assess well performance, reservoir drive mechanism, and original gas-in-place ("OGIP") in a small discovery. The significant implications for in-depth production data analysis, material balance applications, and dynamic reservoir modeling techniques are also emphasized.
Interpretation of discovery well flow performance established the flow potential of a prolific gas producer corresponding to its associated down-hole and surface conditions in what was originally thought to be a single well subsea tieback development. Indepth analysis of the initial pressure and production data offered an early estimate of OGIP providing indications of reservoir compartmentalization before the reservoir drive interpretation of OGIP for the field was fully understood and enabled monitoring of aquifer invasion. Accurate, continuous surface and down-hole surveillance facilitated interpretation of reservoir depletion and in conjunction with sequential, unscheduled shut-ins during the production life of this subsea tieback, the true geometry of the structure was revealed and the impact of aquifer encroachment was quantified.