bluuebunny/crossref_metadata_2025 huggingface dataset:
Estimating CO2 Fluxes Along Leaky Wellbores
Authors: Tao Qing , Checkai Dean A. , Huerta Nicolas J. , Bryant Steven L.
Published: June 2014

Large-scale geological storage of carbon dioxide (CO2) is likely to bring CO2 plumes into contact with a large number of existing wellbores. The flux of CO2 along a leaking wellbore requires a model of fluid properties and of transport along the leakage pathway. Knowing the range of effective permeability of faulty cement is essential for estimating the risk of CO2 leakage. The central premise of this paper is that the leakage pathway in wells that exhibit sustained casing pressure (SCP) is analogous to the rate-limiting part of the leakage pathway in any wellbore that CO2 might encounter. Thus, field observations of SCP can be used to estimate transport properties of a CO2-leakage pathway. Uncertainty in the estimate can be reduced by accounting for constraints from well-construction geometry and from physical considerations. We then describe a simple CO2-leakage model. The model accounts for variation in CO2 properties along the leakage path and allows the path to terminate in an unconfined (constant-pressure) exit. The latter assumption provides a worst-case leakage flux.

By use of pathway permeabilities consistent with observations in SCP wells, we obtain a range of CO2 fluxes for the cases of buoyancy-driven (post-injection) and pressure-driven (during injection) leakage. Assuming the frequency distribution is representative of SCP wells, we observe that in leakage pathways corresponding to the slow but nonnegligible buildup of casing pressure (several psi/D), the effective permeability of the leakage path is in the range of microdarcies to hundreds of microdarcies, and the corresponding CO2 fluxes are comparable with naturally occurring background fluxes observed at the ground surface. In pathways corresponding to intermediate and fast buildup rate of casing pressure (tens to hundreds of psi/D), the effective permeability is in the range of tenths to tens of millidarcies, and the CO2 fluxes are comparable with surface flux measurements at the Illinois basin and at the natural seep at Crystal Geyser (Utah). In pathways corresponding to very fast buildup rate (thousands of psi/D), the effective permeability is from tens to hundreds of millidarcies and the CO2 fluxes are up to three orders of magnitude higher than those measured at Crystal Geyser.
Effect of Oil-Viscosity-Gradient Presence on SAGD
Authors: Chen Joyce , Ito Yoshiaki
Published: June 2014

The presence of an oil-viscosity gradient appears to be a real phenomenon in the field, and its influence on the steam-assisted-gravity-drainage (SAGD) process has been studied by various researchers. However, there is potential to refine previous results to exploit the impact of viscosity gradients on SAGD-oil-recovery-process performance. This paper covers our simulation study of the impact of an oil-viscosity-gradient presence on SAGD operation. Various SAGD operating scenarios in the reservoir with the presence of a vertical oil-viscosity gradient were investigated and simulated. The conclusions are summarized as follows:

The presence of a vertical oil-viscosity gradient in the reservoir had a mild effect on the SAGD-oil-recovery rate, while the effect on the oil-recovery factor was insignificant.

J-Well SAGD, in which a J-well replaces the horizontal producer in a standard SAGD-well configuration, did not perform as well as SAGD with a standard well configuration (two parallel horizontal wells). These two conclusions are not in agreement with previous findings by other research groups.

Observations from some SAGD field tests indicate that the steam chamber could fail to reach the top of reservoirs. For those cases, gas injection could potentially help to recover the oil from the layer above the steam chamber. If that is true, the presence of an oil-viscosity gradient might have some impact on SAGD performance with gas injection.

Because local steam-trap control is required for J-Well SAGD (JAGASS) operation to optimize performance, the challenge and feasibility of local steam-trap control are also discussed in this paper. Some of the SAGD field evidence will be provided to support our simulation results.
Drilling a Better Pair: New Technologies in SAGD Directional Drilling
Authors: Zimmer Chad , Richter Dean , Person John , Tilley Jim , Bittar Michael
Published: June 2014

The precise placement of well pairs is one of the most-crucial factors in the successful execution of a steam-assisted-gravity-drainage (SAGD) drilling program. A SAGD drilling program includes placing the producer well relative to the reservoir boundaries and twinning the producer with the injector well accurately. Delivering on these high expectations in unconsolidated formations (e.g., the McMurray oil sands in Canada) requires a strong focus on technological innovation.

A common practice in drilling SAGD wells in northeast Alberta is to drill lateral SAGD pairs with conventional, steerable mud motors and logging-while-drilling (LWD) resistivity measurements. Although this combination has delivered success, certain limitations exist in terms of wellbore quality and placement. At a demonstration project by a major oil company, several industry firsts were implemented successfully, including a combination of the newest and most-cutting-edge directional, measurement, and LWD technology.

The keystone of these industry firsts was the application of a soft-formation-modified, point-the-bit rotary-steerable system (RSS) used on 20 horizontal wells. Combined with an ultradeep azimuthal resistivity sensor, the RSS provided precise geosteering along the bottombed boundary in the producer wells, resulting in improved reservoir capture and characterization. More on-bottom time enabled more-efficient drilling and reduced well costs significantly. Highly smooth liner runs reflected the lack of tortuosity in the wellbore, made possible by the rotary bottomhole assembly (BHA). Improved directional control made uniform well separation possible between lateral pairs, thereby reducing the risk of hot spots and short circuiting during SAGD operations. The use of an even-walled power section above the RSS increased the bit rev/min for improved BHA responsiveness while minimizing casing and pipe wear. Overall, the results and lessons learned from the demonstration of these new techniques provide a clear indication of the progressive future of directional drilling in SAGD.
A Fully-Coupled Geomechanics and Flow Model for Hydraulic Fracturing and Reservoir Engineering Applications
Authors: Charoenwongsa S. , Kazemi H. , Miskimins J. , Fakcharoenphol P.
Published: June 2014

In this paper we present a practical fully-coupled geomechanics and flow model for application to hydraulic fracturing, especially in tight gas reservoirs, and other reservoir engineering applications. The mathematical formulation is consistent with conventional finite-difference reservoir simulation code to include any number of phases, components and even thermal problems. In addition, the propagation of strain displacement front as a wave, and the relevant changes in stress with time, can be tracked through the wave component of the geomechanics equations. We show the development of an efficient finite-difference computer code for rock deformation including thermal and wave propagation effects. The numerical approach chosen uses two different control volumes—one for fluid and heat flow and another one for rock deformation.

The ultimate goal is to provide a tool to assess the effect of pore pressure, cooling or heating the reservoir, and propagation of a strain wave resulting from hydraulic fracturing on the reservoir rock frame. This information is crucial for determining the effect of shear stress on opening or closing of natural fractures during creation of hydraulic fractures, and changes in shear- and compressional- wave velocities for seismic imaging purposes. A specific application of the product of this research is to simulate fracture propagation, gel cleanup and water block issues in hydraulic fracturing.

The modeling results indicate significant change in shear stresses near hydraulic fractures as a result of hydraulic fracture face displacement perpendicular to the fracture face and not as much from pore pressure change because the filtrate does not travel very far into the reservoir. Similarly, temperature change effects are also very significant in changing stress distribution.
Technology Options and Integration Concepts for Implementing CO2 Capture in Oil-Sands Operations
Authors: Ordorica-Garcia Guillermo , Nikoo Mehrdokt , Carbo Michiel , Bolea Irene
Published: June 2014

The majority of the technology development for CO2 capture and storage (CCS) is driven by the electric-utility industry, in which the emphasis is on large centralized units for electric-power generation with coal as the primary fuel. The implementation of CCS in oil-sands operations has significant potential to provide meaningful carbon-emissions reductions. This paper presents various concepts for integrating leading CO2-capture techniques to bitumen-extraction and -upgrading processes. The main carbon-capture technologies are reviewed, and their relative advantages and disadvantages for implementation in bitumen mining, thermal bitumen extraction, and bitumen upgrading are discussed, leading to a qualitative assessment of their suitability for each oil-sands process.
Unique CO2-Injection Experience in the Bati Raman Field May Lead to a Proposal of EOR/Sequestration CO2 Network in the Middle East
Authors: Sahin S.. , Kalfa U.. , Celebioglu D..
Published: June 2014

Carbon capture and storage (CCS) is one of the most important emission-reduction technologies available for large stationary CO2 sources. Fossil-fueled power generation is the largest source of carbon dioxide (CO2) that could be captured and stored. Depleted oil and gas fields and major CO2 sources nearby are ideal places for large-scale geological storage. Injection of CO2 into a depleted reservoir can enhance the recovery of hydrocarbons. The circumstances, in fact, dictate that the CO2 enhanced-oil-recovery (EOR) industry and power-generation sector should be eager to magnify the mutually beneficial link between CO2 EOR and new industrial sources of CO2.

In 1986, the Turkish Petroleum Corporation (TPAO) started the first large-scale immiscible-CO2-injection project in southeastern Turkey. Approximately 1 million tons/yr of naturally occurring CO2 has been injected into Garzan carbonates in the Bati Raman field. A substantial increase in the production rate and ultimate recovery has been experienced, and this is expected to continue. The Bati Raman immiscible-CO2-injection project has been acknowledged as one of the most unique and successful EOR applications in the history of heavy oil in fractured-limestone reservoirs.

There are nearly 50 oil fields in Turkey, and a significant proportion of them would be potentially suitable for EOR. If sufficient volumes of CO2 were economically available, many of these could produce incremental oil for an extended period. It is a fact that sedimentary basins in the Middle East are typically carbonates, and this limits the selection of EOR processes significantly. Having observed CO2 injection as an excellent choice for carbonates through experience with the Bati Raman field, one may extend the CO2 network idea to the whole region. This will not only activate the enormous EOR potential in the mature fields of the Middle East, but also the permanent storage of CO2 through a common effort.

The use of captured CO2 for EOR will become feasible if CO2-recovery plants with a higher CO2 content give an attractive CO2 delivery cost and emission rights can be traded in the carbon market, which was introduced by the Kyoto protocol. The major challenges would be formulating a working and acceptable model between petroleum and power sectors and to establish a market mechanism to ensure that this system becomes economically feasible.
Perspectives on CCS Cost and Economics
Authors: Kheshgi H.S.. S. , Thomann H.. , Bhore N.A.. A. , Hirsch R.B.. B. , Parker M.E.. E. , Teletzke G.F.. F.
Published: June 2014

Focus on carbon capture and storage (CCS) has grown over the past decade with recognition of CCS's potential to make deep CO2-emission reductions and that fossil fuels will continue to be needed to supply much of the world's energy demands for decades to come. How CCS will compare with other options in the future depends critically on the cost of CCS (the focus of this paper) and resolution of barriers to CCS deployment and costs and barriers for other emission-reduction options.

This paper provides a comparison of the cost of electricity of five power-generation options—gas combined cycle gas turbine (CCGT) and supercritical coal with and without CCS and nuclear—and shows regions of carbon price and fuel prices where each can be economically viable.

Current cost estimates for coal CCS for nth-of-a-kind power-generation plant are in the USD 60 to 100/t of CO2 avoided, which is higher than some of the earlier CCS estimates, and higher than the generally accepted range of expected carbon prices in the next 2 decades. The high cost of coal CCS suggests that Gas-based power generation is significantly more economical than coal CCS at carbon prices less than USD 60 to 100/t CO2.Even after carbon prices reach USD 60 to 100/t CO2, gas CCS produces lower-cost electricity than coal CCS, as long as natural-gas prices remain less than USD 9/MBtu.Nuclear has a lower cost of electricity than coal CCS. Although coal or gas CCS is unlikely to be economical in power generation over the next 2 decades, subsidized demonstrations of CCS are likely to occur. In addition, components of CCS technologies will continue to be economically practiced in early-use segments [e.g., natural-gas processing and enhanced-oil-recovery (EOR) operations]. In the natural-gas-processing industry, CO2 separation cost is a fraction of the cost of CO2 capture in power generation because of its higher gas pressure, and the CO2 separation is typically necessary to monetize the natural-gas resource.

In contrast, CCS for most refinery and industrial emissions is expected to be significantly more costly than in power generation because the CO2 streams are typically smaller scale and more distributed than those from large power plants.

Realistic cost estimates for CCS and for other greenhouse-gas (GHG) mitigation options are an important input for focusing research, development, and demonstration addressing barriers to applications that show the greatest promise and for development of sound policy.
Characteristics of Slug Flow in a Vertical Riser
Authors: Abdulkadir M. , Hernandez-Perez V. , Abdulkareem L. , Lowndes I. S. , Azzopardi B. J.
Published: June 2014

This paper presents the results of a series of experiments conducted on a vertical 67 mm internal diameter riser to study the characteristics of slug flow generated within a multiphase air-silicone oil mixture, for a range of injected superficial gas and liquid flow rates. Air/ silicone oil flows in a riser have been investigated using advanced instrumentation called Electrical Capacitance Tomography (ECT), described in Hammer (1983), Huang (1995) and Zhu et al. (2003). The ECT was used to determine: the velocities of the Taylor bubbles and liquid slugs, the slug frequencies, lengths of Taylor bubbles and liquid slugs, the void fractions within the Taylor bubbles and the liquid slugs over a range of superficial liquid (0.047≤USL≤0.38 m/ s) and gas (0.344≤USG≤0.745 m/ s) velocities. An examination of the experimental data concluded that the rise velocity of the observed Taylor bubbles (structure velocity) were strongly dependent on the mixture superficial velocity. The void fraction within the liquid slug and the Taylor bubbles were observed to increase with gas superficial velocity. The lengths of liquid slug and Taylor bubbles were also observed to increase with an increase in the gas superficial velocity. The liquid slug frequency was observed to increase as the liquid superficial velocity increases, but was observed to be weakly dependant on the superficial gas velocity.
Flow Regime Analysis Assists Early Detection of a Shallow Gas Kick
Authors: Asakereh Reza
Published: June 2014

An intrusion of unwanted formation fluids into wellbore in presence of drilling fluid is called a "Kick". Kick happens because either hydrodynamic pressure of drilling fluid (ECD) is not sufficient against the pressure of formation fluids or with a sufficient mud weight, drilling operation reaches to a Geopressure formation with pressure greater than the pressure exerted by the drilling fluid dynamically. Study of 172 blowout cases world-wide shows that 33% of them were shallow gases, and the consequence of more than half of these was damage to or total loss of drilling rig. In this paper, focus is on major indications of shallow gas kick, specially flowline variations, and how dynamic and motional parameters of fluid can be utilized to detect kick quickly. Anatomy of a shallow gas, include its generation and geology is explained in this paper. Positive kick indications also are analyzed. All types of gas intrusion into wellbore formulas are evaluated and 4 new first time flow regime formulas have been derived from original formulas like annular Reynolds number and annular velocity in both normal and flow conditions. A conceptional Annular Acceleration parameter has been introduced for the first time in the history of drilling engineering. Finally in the last, author suggests a real time monitoring system like those used in mudlogging units and assembled from sensors and monitoring software package that is tied with diverter system and runs the diverter operation automatically. The system can distinguish shallow gas from several events that happen in circulation system like mud weight modification, pit to pit transfer, mud dumping etc.
Identification and Quantification of Thinly Bedded Low Resistivity Pay in the Niger Delta
Authors: Mogbolu Peter O.
Published: June 2014

In some fields in the Niger Delta, there are reservoirs that have thin laminations of sands and shale, which contain hydrocarbons, but are either not identified as hydrocarbon bearing, or the hydrocarbons-in-place are not properly quantified. During data acquisition in wells using conventional logging tools the actual resistivity of such thin-bedded pay zones are not measured, because of the poor vertical resolution of the tools (compared to the thickness of the laminations). This results in both ‘a problem with detection’ (low contrast between the hydrocarbon pay zones and water-bearing intervals) and ‘a substantial uncertainty in quantification (and usually under-estimation) of the hydrocarbon volumes’.

In this study, an analytical approach is shown on how to properly quantify the volumes in place and recovery, starting with the proper petrophysical evaluation methods, and how the resulting properties are used to estimate the hydrocarbon volumes in the thin-bedded low resistivity pay zones.
Efficient and Robust Uncertainty Quantification in Reservoir Simulation with Polynomial Chaos Expansions and Non-intrusive Spectral Projection
Authors: Sarma Pallav , Xie Jiang
Published: June 2014

Polynomial Chaos Expansions (PCE) as applied with the Probabilistic Collocation Method (PCM) has been shown to be a promising approach for uncertainty quantification in reservoir simulation. In particular, it has been shown to be more accurate and efficient compared to traditional experimental design (ED). PCEs have a significant advantage over other response surfaces as they theoretically guarantee convergence to the true distribution (of the output random variable of interest, such as cumulative oil production) as the order of the PCE and number of simulations used to calculate the PCE coefficients is increased. However, there are many issues with PCM that limit the practical applicability of the method to large scale problems. A key issue with the PCM approach is that the number of simulations required to create the PCE is directly dependent on the number of terms in the PCE, and this increases exponentially with PCE order and number of random variables.

We propose the application of another related approach that also uses PCEs called Non-Intrusive Spectral Projection (NISP) that essentially eliminates many of the key problems with PCM. The main difference with PCM is that instead of using a collocation or regression approach to estimate the PCE coefficients, a sampling approach is used in NISP. This makes the number of simulations almost independent of the number of random variables and PCE order, and as a result is much more efficient for large-scale problems. Furthermore, statistically rigorous error estimates on the PCE coefficients are also provided with this approach. We also propose a robust approach for eliminating PCE coefficients that have been estimated incorrectly, thereby improving the accuracy and robustness of NISP. The accuracy and efficiency of the approach is demonstrated through various examples.
Novel, Multistage Stimulation Processes Can Help Achieve and Control Branch Fracturing and Increase Stimulated Reservoir Volume for Unconventional Reservoirs
Authors: Romanson Roch , Pongratz Reinhard , East Loyd , Stanojcic Milorad
Published: June 2014

In 2010, natural-gas production rates in the USA for March and April were the highest since 1974 (US Energy Information 2010). This is largely related to recent success in exploiting unconventional reservoirs and successful development and implementation of innovative technologies. In Europe, unconventional reservoirs (in particular shale gas) are receiving considerable attention. Basins with potential shale-gas plays exist, as does the infrastructure to transport gas to the end user. In addition, the gas-price scenario is favorable as well. It will be critical to find US analogs and transfer technologies/processes that will facilitate European shale-play developments into economically successful projects. However, the market and challenges in Europe are significantly different from those in the US. The population density is much higher and environmental regulations will play a different role. In addition, the entire industry is set up different with a lot less drilling rigs and other service providers. For different reasons, costs are somewhat higher than in the US as well. This demands optimization from Day 1. Directional drilling of horizontal wells needs to progress toward sweet spots, and the completion and fracturing process must be optimized starting at the first well. Therefore, it is important to understand the technologies that were game changers in the US, identify their applicability in Europe, and implement them properly.

This paper discusses two recently developed hydraulic-fracturing processes and a hybrid unit that might have considerable impact on advancing economic recovery of unconventional reservoirs. The first new process is designed for high-pumping-rate, multistage fracturing treatments with low proppant concentration. Highly concentrated proppant slurries are pumped down the coiled tubing (CT), jointed tubing (JT), or combination string, and nonabrasive, clean fluid is pumped down the annulus. In such pumping scenarios, the permanent well tubulars are saved from erosion. The pumping rate can be manipulated in real time to customize the placement and downhole-proppant concentration instantly. In case of premature screenout, a well could be easily reverse circulated and cleaned for the next stage. The combination of downhole mixing and microseismic fracture mapping provides unprecedented control of fracture execution to facilitate branch fracturing. The second new process is a combination of mechanically activated sleeve completions and fracturing of individual intervals, but with a change in the sequence in which the intervals are stimulated. This new method is proposed with a goal of altering the stress in the rock to facilitate (or enhance) branch fracturing and connect to induced stress-relief fractures in a single, horizontal well.
Riser Less Well Intervention for Subsea Work Over
Authors: Skeie Terje , Hjorteland Øyvind , Arnskov Michael Macdonald
Published: June 2014

The number of subsea wells has increased steadily over the years and is estimated to have exceeded 5500 by the end of 2010.

Subsea wells do in general have substantially lower recovery rates than what is normally achieved from comparable nonsubsea wells. This is due to the high intervention costs which are directly related to the rates of the rigs required to carry out such operations if the traditional and conventional approach is adopted. Hence the incentive to increase recovery rates has been limited as the balance between cost and revenue has been unfavorable, even with increasing oil and gas prices. However, this has also stimulated the development of alternative methods which can enhance recovery rates and not least address the challenges created by more fields passing maturity and exploration moving to more demanding areas.

Lightweight and riserless intervention well intervention has in this context become a proven approach with considerable potential for driving the future development. The ability to substitute large rigs with smaller and dynamically positioned light well intervention vessels has a major impact on cost and time. Riserless intervention as such has been done regularly for a number of years and has set excellent HSE standards. However, in recent years the use of riserless well intervention has become increasingly instrumental in the effort to enhance recovery rates and general performance.

The paper gives an account of a scale milling operation carried out at a Norwegian field in the North Sea where two wells both suffered from a significant drop in production.
Successful Applications of Pressure-Rate Deconvolution in the Cad-Nik Tight Gas Formations of the British Columbia Foothills
Authors: Jones Jack R. , Chen Andrew
Published: June 2014

The Cadomin-Nikanassin (Cad-Nik) sandstone formations in the Lower Cretaceous reservoirs along the reverse-thrust faulting belt of northeastern British Columbia (NEBC), Canada, have emerged in recent years as a new tight gas play. The low porosity (3?6%) of the rock matrix controls gas storativity, while the presence of natural fractures in the form of clusters or swarms allows significant and sustainable flow rates for commercial production. Newly drilled wells are commonly hydraulically fractured to establish or enhance wellbore connectivity to the natural-fracture network.

Seismic mappings of these structural unconventional-gas reservoirs provide the early assessments of resource sizes and initial gas in place (IGIP), which usually bear large uncertainties because of the difficulty in determining reservoir structural closures and pay-porosity cutoffs. Regional analogue wells are often used to guide development decisions. Meanwhile, estimating connected reservoir volumes through conventional-gas material balances (p/z vs. cumulative production) and production-data analysis [rate-transient analysis (RTA)] has not been without challenges. Fairly long pressure buildups (PBUs), on the order of hundreds of hours, are often performed without seeing the pressure stabilization required to estimate accurately the reservoir pressure needed for material-balance calculations. The applicability of pressure extrapolation to these tests has not been systematically investigated; therefore, no reliable methods for using shorter shut-ins to estimate reservoir pressure currently exist. Thus, reliable average reservoir-pressure estimates require significantly longer well shut-in times in order to perform meaningful gas material balance. Because this is not practical, confidence in material-balance results requires a second, independent method for establishing connected well volumes to be used in comparisons and cross checking. One possible choice is RTA, but, in these fields, numerous times wellhead-pressure data are also unavailable or unreliable.

This paper presents two field-case studies that demonstrate the successful application of the pressure/rate-deconvolution approach, combining a well?s long, high-quality production-rate history with accurate downhole-pressure data from relatively short buildup tests. This approach allows the reservoir engineer to (1) reconcile the performance-based estimated-ultimate-recovery estimates with the volumetric IGIPs; (2) establish, at the least, minimum well-drainage size and connected volume; and (3) select possible infill-drilling opportunities. A final benefit is that this often leads to a better understanding of well/reservoir parameters.
Fast Track Well Surveillance and Application Integration Ready for First Oil: The Frade Story
Authors: Honeycutt David , Chacon-Fonseca Joel , Kumar Sujatha , Nelson Andrew
Published: June 2014

Offshore Oil and Gas operators need solutions that are ready to use, quick to deploy, and intuitive to use in order to reap the benefits that digital technologies are promising. However, all too often, issues such as complex applications and workflows, and resistance to change work together to cause unacceptable delays in deploying these solutions. This paper presents the experience of the Chevron Frade i-Field deployment project, which used out-of-the-box solutions that were configured and integrated in a short timeframe to deliver a solution that was ready for the project's First Oil.

This paper will explore how this fast-track integration was accomplished as well as the benefits that Chevron experienced as a result of the speed of its deployment. Some of the issues to be explored: The business context – Oil and Gas companies strive to mitigate risks associated with First Oil, as well as operability and production targets. The ability to monitor and provide end to end visibility to quickly diagnose the root cause of issues was critical to start-up and sustainable operations.The technologies – The project successfully deployed a real-time well performance monitoring and calculation solution, an integrated model-centric production simulation solution, and a pressure transient analysis suite that was connected to the real-time data available at the FPSO. Data was captured from data sources such as the wells, subsea equipment and facilities, then pre-cleansed to ensure quality of the calculations.The benefits – In addition to the anticipated benefits of the solution, Chevron experienced a number of unexpected benefits due to the fact that the project was up and running before First Oil. Chevron production, reservoir, and facility engineers diagnosed several field start-up teething issues. In several instances, well and FPSO stability issues were successfully diagnosed from onshore, leading to actions that reduced downtime and prevented loss of production during the startup process. This data integration effort continues to reduce the amount of time required to diagnose problems and allows for optimization of production opportunities.
Innovative In-situ Natural Gas Huff "n" Puff in the Same Wellbore for Cost-effective Development: A Case Study in Sudan
Authors: Xueqing Tang , Guocheng Li , Ruifeng Wang , Xianghong Wu
Published: June 2014

This paper illustrates the natural gas in-situ huff and puff pilot test applied in Jake field in Sudan. B pool of Jake field is a medium GOR (100 scf/bbl) pool with medium well productivity, averaging at 500 BOPD by PCP testing. Operator intended to increase well output to reduce operational and safety hazards. Substantial high pressure natural gas below B pool could be utilized and injected into B pool to boost recovery factor. This process undergoes injection, soaking, production, similar to steam huff and puff. Pilot test of in-situ huff and puff has been planned by following methodology: 1) driving mechanisms investigation of huff and puff and confirm applicability in B pool; 2) gas production from tubing and injection into B pool through casing without using gas compressors; 3) injection and production parameters optimization by nodal analysis;

Pilot test on two wells JS-4 and JS-1 began in Aug. 2010 and flowed naturally after 20 days injection and gained 20 fold well rate increase compared with PCP wells, amounting to 10000-13000 BOPD, setting the highest well rate record in Sudan. Conclusions drawn from pilot tests were as follows:1) in-situ natural gas huff and puff was feasible; 2) gas injection could boost reservoir pressure and reduce in-situ viscosity and enhance recovery factor; 3) gas from tubing into casing was proved simple, efficient and cost-effective 4) production rates could be optimized using nodal analysis.

Sudan is abundant in layered pools with lower gas and upper light oil, natural gas in-situ huff and puff has wide applications for similar pools in Sudan.

Successful natural gas huff and puff pilot test in this paper highlighted huge oil rate gain, innovative well bore structure, cost-effective operation, paving the way for future full field implementation.
Coupled Surface/Subsurface Simulation of an Offshore K2 Field
Authors: Dobbs Walt , Browning Brad , Killough John , Kumar Amit
Published: June 2014

Modern simulation capabilities were recently applied to the K2 Field to help define a risk-reducing phased development. This integrated study relied heavily on new advances to handle complex fluid behavior, derive a history match, resolve future behavior of sub-sea wells, and seamlessly review economic metrics.

Simulations used tightly-coupled surface and subsurface calculations to capture and stabilize the interaction of surface facilities with the reservoir. This robust and rigorous approach improves upon previously reported techniques in which subsurface flow calculations are only loosely coupled to the surface network. Fluid characterization involved a single equation of state with multiple distributed component sets in reservoirs and compositional mixing within the surface network. Super-critical initialization was used to represent an unusual compositional transition from a highly undersaturated oil rim to an undersaturated gas cap. History match parameters included reservoir, facilities, and well properties.

A host of development options involving artificial lift (AL), additional wells, miscible gas injection, and water injection was evaluated for economic value through an optimization-under-uncertainty approach. This assessment guided a multi-disciplinary project team to detail a short set of developments for highest consideration in a common situation where the complex interactions among the reservoir, wells, outflow network, and facilities, makes an intuitive solution inaccessible. Although the four geologic models used were considered adequately diverse for the study, further value lies in broadening the geological uncertainty and hence the range of possible outcomes.

While a relatively new application in deepwater fields, AL is recognized as a technology to extend producing life for mature fields and enable production from challenging plays such as the Gulf of Mexico lower Tertiary. Few case studies addressing such situations are available. The presented workflow may be repeated on assets with significant outflow performance drivers – assets that would benefit from modeling and resolution of complex surface/subsurface interactions.
Non Intrusive Corrosion-Erosion Monitoring for Subsea Applications
Authors: Kristiansen Sindre Halse , Instanes Geir
Published: June 2014

The oil and gas industry has a need for reliable monitoring of changes in wall thickness both topside and subsea. It is important to detect and monitor the effect of corrosion and erosion as this may reduce the life-cycle cost and increase the lifetime of industrial infrastructure, ships, aircrafts, ground vehicles, pipelines, oil installations, etc. Even topside the conditions of operation can be extremely hostile, facing problems like surface roughness, fluid loading issues, temperature variations, and a host of other factors that make development of a robust wall thickness assessment tool a challenging task. Deploying a monitoring system subsea makes the application even more demanding when you have to take into account factors like high pressure and limited access. Over the last years ClampOn have offered a topside corrosion-erosion monitor (CEM) for monitoring changes in the wall thickness of such infrastructure. Major advantages of this technology have been its non-invasiveness, high repeatability, high coverage and the lack of any transducer movement, also making it an excellent candidate for subsea use. The measurement principle is based on dispersion of ultrasonic guided wave modes, and by using electromagnetism these waves can be transmitted through the pipe wall without the sensor being in direct contact with the metallic surface. It is installed on the outer pipe wall to produce real-time wall thickness information, not as a spot measurement, but as a unique average path-wall thickness. With several successful installations topside, the technology has now also been made available for subsea installation.
Coiled-Tubing Technologies Improve Shale-Play Development Efficiencies
Authors: Fowler S. Hampton , Lindsay Sharlene , Smith Robert
Published: June 2014

Development of U.S. shale plays has greatly accelerated throughout the past decade and will continue to contribute increased production of gas and hydrocarbon liquids for many years to come. A March report by HIS-Cambridge Energy Research Associates estimates that in 2000, shale gas was only 1% of total production in the U.S., but it now makes up approximately 20% of the total production with the potential to contribute greater than 50% by 2035. The two main technologies attributed with the successful growth in shale-play development are horizontal drilling and fracturing technologies.

Coiled-tubing (CT) equipment and technologies have also aided in the rapid and economical development of shale plays. The demand for these services has increased such that a CT unit is now assigned to each frac crew. Because of CT's capability to continuously circulate, work with live-well pressure, and push to the toe of long, horizontal sections, several tools and methods have been devised to transfer these advantages to stimulation and well-servicing solutions to help optimize production while minimizing time and cost. These technologies include hydrajet and CT-conveyed perforating techniques as well as accurate placement of stimulation treatments with precise and instantaneous proppant-concentration control. Larger CT sizes are being used to enhance treatment rates, service longer horizontals, and provide additional weight or force at the end of the tubing for plug drillouts or manipulating service tools. The trend in longer and larger CT size is also driving the need to optimize the CT unit design to maintain operational efficiency and safety as well as meet Department of Transportation (DOT) regulations. This paper reviews these new CT techniques and trends being used to improve shale play developments with case histories.

The successes demonstrated in the U.S. are now being targeted at shale-play developments in the eastern hemisphere and Latin America to meet their growing demand for clean and economical energy.
Investigation of Wettability Alteration and Oil-Recovery Improvement by Low-Salinity Water in Sandstone Rock
Authors: Nasralla Ramez A. , Bataweel Mohammed A. , Nasr-El-Din Hisham A.
Published: June 2014

Optimization of any oil-recovery process is based on understanding of the recovery mechanisms, whereas the underlying mechanisms of improving oil recovery by low-salinity-water injection are still debated. Wettability alteration is one of the mechanisms suggested to be the primary mechanism of low-salinity water. Therefore, wettability alteration by low-salinity water in sandstone reservoirs is examined by using the contact-angle technique. The effect of changing ionic strength on the electrokinetic charges is investigated by use of the zeta-potential technique to explain the causes of wettability alteration by low-salinity water. Moreover, coreflood experiments were performed in order to correlate between the wettability alteration and oil-recovery improvement caused by low-salinity water. Mica sheets were used for the contact-angle measurements to represent sandstone rock. The effect of water salinity on wettability was studied by using synthetic water over a wide range of salinities (from 0 to 174 000 mg/L), with two different crude oils at different conditions of pressure and temperature. Zeta-potential tests were conducted to measure the electrokinetic charges for combinations of each of the two crude oils or Berea sandstone and different brines. Berea sandstone cores were used for waterflooding experiments by injecting the same brines tested in the wettability measurements. Low-salinity water showed lower contact angles compared with high-salinity water for the two types of crude oil, which demonstrates the ability of low-salinity water to alter the rock wettability to more water-wet. In addition, low-salinity water made the surface charges at rock/brine and oil/brine interfaces strongly negative. As a result, the repulsive forces between rock and oil surfaces increase, which leads to expansion of the double-layer and, consequently, wettability alteration and oil-recovery improvement as confirmed by coreflood experiments.
A Procedure for the Configuration of an Inflow Control Device Completion Using Reservoir Modelling and Simulation in the North Amethyst Pool
Authors: Wu Ray , Turpin Allison , MacDonald Dennis , Kavanagh Dion
Published: June 2014

This paper outlines an approach to simultaneously reduce gas and water production through the design and implementation of an inflow control device (ICD) completion for a horizontal production well in the North Amethyst pool. The procedure uses Schlumberger’s Petrel modelling software, Schlumberger’s reservoir simulator, ECLIPSE, and a multi-segmented well (MSW) model to optimally configure an ICD completion within a reservoir model. This approach utilizes the reservoir model to generate ternary plots (oil, gas and water) that represent three-phase movement within the reservoir. The use of MSW enables the dynamic display of a virtual production logging tool (PLT) plot, representing the expected three-phase inflow performance along the wellbore. Both ternary and PLT plots identify the locations of high gas and high water inflow zones along the wellbore.

With these zones identified, various configurations of ICD completions are designed to control these breakthrough zones and are then simulated. ICD equipment options, such as reduced nozzle sizes and blank zones, are considered in the design. The simulation results of the various ICD configurations are compared to determine the optimal design. The design objectives are to optimize oil inflow, oil rate, and ultimate recovery by delaying and reducing gas and water production. The produced liquid rate was also optimized with rate sensitivities for each ICD configuration which led to a design that further reduces gas and water production.
Comparison of Frac Valves vs. Plug-and-Perf Completion in the Oil Segment of the Eagle Ford Shale: A Case Study
Authors: Stegent Neil A. , Ferguson Kip , Spencer Jon
Published: June 2014

Which completion strategy is better—Plug-n-Perf or Frac Valves? The authors of this paper will evaluate multiple completion strategies in two offset horizontal wells drilled in the oil section of the Eagle Ford shale. The first well was completed using a combination of single entry point, ball-activated frac valves (first two-thirds of the lateral) and plug-n-perf (also designated as P-n-P) with multiple entry points (the remainder of the lateral). The second wellbore was completed using only P-n-P with multiple entry points. Both wells were completed using comparable completion designs (hybrid fracture design, number of fracture stages, pounds of proppant, etc.) and were cemented for annular isolation.

To determine the completion and production efficiency, microseismic mapping and oil-soluble tracer technologies were used to evaluate the differences between the completion strategies. Fracture mapping was used to compare stage "complexity," while a hydrophobic oil tracer, which generated a pseudo-production log of each individual stage, was used to determine the completion efficiency.

The integration of these diagnostic engineering technologies allows for interesting conclusions with respect to the fracture complexity generation from the different completion strategies, as well as the resulting production from the comparative wells. This data can provide important information regarding the difference between the two completion methods.
The Full-Automatic Real-Time Display, Testing and Adjustable System in Separated Layers Water Injection Well
Authors: Wang Feng Shan , Xu De Kui , Yu Lei , Zhang Feng Hui , Liu Chong Jiang , Zhu Zhen Kun
Published: June 2014

This paper presents very important water flooding equipment which has been applied successfully in Daqing oilfield in China. This finished product is integrative, intelligent, automatic, real time monitoring, it is a reliable way to collect every layer's pressure, temperature, water injection rate, the testing time, etc., displays and monitors all these data on the laptop screen in real time. The testing workers use the laptop to adjust every layer's water injection rate and all the data records as safely and conveniently as possible. All these recorded data can be used in optimization reservoir development scheme, casing damage monitoring and prevention.

This full-automatic intelligent testing and adjusting equipment system is very suitable for application in poor geological condition, complex oil and water distribution, the single water injection well is separated several layers. Testing, adjusting, recording data can be used laptop to control during the operation. This full-automatic intelligent testing equipment system reduces the working intensity, the testing work-force and the production costs, improves the water injection rate in high water cut-stage oilfield.

This system has been awarded three invention patents and twenty patents for utility model. The single water flooding well testing cost has been reduced 47% in practical application. So far, more than four thousand water flooding wells have been applied with this equipment in Daqing oilfield, totals about six thousand well-times. The testing, adjustable successful rate has been above 85% in one trip, the precision has been increased nearly 10%. The average testing, adjustable time of single water injection well is less than two days which has been more than trebled as against before, the totaled economic benefits is about millions US dollars per year. More than twenty Chinese Oil Production Companies in five different oilfields have applied this equipment.