bluuebunny/crossref_metadata_2025 huggingface dataset:
A New SAGD-Well-Pair Placement: A Field Case Review
Authors: Jorshari Kamran , O'Hara Brendan
Published: June 2014

Steam-assisted gravity drainage (SAGD) has been improved consistently by experimenting with various solutions in both oil sands and heavy-oil fields in Canada (Butler 1994; Singhal et al. 1998). The SAGD process consists of two stacked horizontal wells and is proven technology in heavy-oil fields (Butler and Yee 2000). Employing the same concept of gravity drainage, SAGD-well placement convention has been revisited and challenged many times (Birrell and Putnam 2000; Edmunds 1991; Parappilly and Zhao 2009). Known to the industry, the cross-SAGD (also called XSAGD) (Stalder 2007) and J-shaped well steam-assisted gravity drainage (JAGD) (Larter et al. 2008) processes are two examples of fit-for-purpose well design and recovery schemes that require unique drilling practices. The Celtic pool, located in Lloydminster, Saskatchewan, is an active Husky Energy Incorporated (Husky) thermal field that includes 31 SAGD well pairs. In this heavy-oil pool, one of the SAGD well pairs (I3/I4; Well I3 as producer and Well I4 as the injector) experienced production downtime soon after coming into service. Following numerous unsuccessful service jobs, several re-entry options were suggested in order to recover remaining reserves. These included sidetracking Well I3, redrilling a new well from the same pad location, or commencing a new well from a different surface location. These cases were ranked, and in 2010, on the basis of a drilling-risk assessment, the new horizontal producer well (I3A) was drilled close to the existing well pair. Well I3A was placed counter currently below the existing injector well (I4) and set successfully parallel to the abandoned Well I3. Steam conditioning was completed in the first quarter (Q) of 2011, and the new SAGD well pair (I3A/I4) has been put on production successfully.

The new well pair was positioned in the opposite direction of a conventional SAGD-well-pair placement. This paper presents the original I3/I4 pair performance, the challenges, results of redrilling Well I3A, reservoir-simulation study, and recent field production of the I3A/I4 SAGD well pair.
Effect of Completion Heterogeneity in a Horizontal Well With Multiple Fractures on the Long-Term Forecast in Shale-Gas Reservoirs
Authors: Nobakht Morteza , Ambrose Raymond , Clarkson Christopher R. , Youngblood Jerry E. , Adams Rod
Published: June 2014

Shale gas reservoirs have become a significant source of gas supply in NorthAmerica because of the advancement of drilling and stimulation techniquesenabling commercial development. The most popular method for exploiting shalegas reservoirs today is the use of long horizontal wells completed withmultiple-fracturing stages [multifractured horizontal wells (MFHW)]. Thestimulation process may result in biwing fractures or a complexhydraulic-fracture network. However, there is no method to differentiatebetween these two scenarios with production data analysis alone, makingaccurate forecasting difficult.

For simplicity, hydraulic fractures are often considered biwing whenanalyzing production data. A conceptual model that is often used for analyzingMFHWs is that of a homogeneous completion in which all fractures have the samelength. However, fractures of equal length are rarely if ever observed (Ambroseet al. 2011).

In this paper, production data from heterogeneous MFHWs (i.e., where allfracture lengths are not the same) is studied for reservoirs with extremely lowpermeability. First, the simplified forecasting method of Nobakht et al.(2012), developed for homogeneous completions, is extended to heterogeneouscompletions. For one specific case, the Arps' decline exponent is correlated tothe heterogeneity of the completion. It is found that, as expected, Arps'decline exponent (used after the end of linear flow) increases with theheterogeneity of the completion. Finally, it is shown that ignoring theheterogeneity of the completion can have a material effect on the long-termforecast.

We have assumed planar hydraulic-fracture geometries for our modelling inthis work and discuss the implications of this when more-complex fracturegeometries are created. This seems to be more common in shale gas reservoirs.We provide an example of low-complexity, planar fracture geometries creatednear an MFHW and observed on an image log at an offset well.
Shale Gas: Nanometer-Scale Observations and Well Modelling
Authors: Silin Dmitriy , Kneafsey Timothy J.
Published: June 2014

Our studies of the underlying fundamental gas-recovery mechanisms from shale gas are motivated by expectations of the increasing role of shale gas in national energy portfolios worldwide. We use pore-scale analysis of reservoir shale samples to identify critical parameters to be employed in a gas-flow model used to evaluate well-production data. We exploit a number of 3D-imaging technologies to study the complexity of shale pore structure: from low-resolution X-ray computed tomography (CT) to focused ion beam and scanning electron microscopy (FIB/SEM). We observe that heterogeneity is present at all scales. The CT data show fractures, thin layers, and density heterogeneity. The nanometer-scale-resolution FIB/SEM images show that various mineral inclusions, clays, and organic matter are dispersed within a volume of few-hundred µm3. Samples from different regions differ sharply in the shape, size, and distribution of pores, solid grains, and the presence of organic matter. Although the samples have clearly distinguishable signatures related to the regions of origin, extremely low permeability is a common feature. This and other pore-scale observations suggest a bounded-stimulated-domain model of a horizontal well within fractured shale that accounts for both compression and adsorption gas storage. Using the method of integral relations, we obtain an analytical formula approximating the solution to the pseudopressure diffusion equation. This formula makes fast and simple evaluation of well production possible without resorting to complex computations. It ss a decline curve, which predicts two stages of production. During the early stage, the production rate declines with the reciprocal of the square root of time, whereas later, the rate declines exponentially. The model has been verified by successfully matching monthly production data from a number of shale-gas wells collected over several years of operation. With appropriate scaling, the data from multiple wells collapse on a single type curve. Pore-scale image analysis and the mesoscale model suggest a dimensionless adsorption-storage factor (ASF) to characterize the relative contributions of compression and adsorption gas storage.
Simulation of Noncondensable Gases in SAGD-Steam Chambers
Authors: Gittins Simon , Gupta Subodh C. , Zaman Maliha
Published: June 2014

Cenovus Energy has been developing the Foster Creek and Christina Lake projects using the steam-assisted gravity-drainage (SAGD) process successfully. The SAGD process at both these projects has been operated at well above the initial reservoir pressure for extended periods of time and this has been simulated adequately using dead-oil models, which omit solution gas from the simulations. As we move into later stages in the life of the more mature well pairs at these projects, it is important to understand the role of noncondensable gases on the development of the steam chambers better in order to optimize the methane-coinjection, steam rampdown, and, ultimately, blowdown phases of operations. Cenovus is also testing reduced-pressure SAGD and solvent-aided processes (SAPs) at these projects, and simulations indicate that noncondensable gas will play a significant role in these processes. Hence, understanding the flow behaviour of noncondensable gases in SAGD steam chambers could have far reaching consequences for lowering the energy intensity and associated costs, and reducing the environmental impact of bitumen production while potentially increasing reserves. This paper presents the results of some recent simulations which are improving our understanding of the role of solution gas in SAGD and the impact of noncondensable gases on steam chamber development.
Innovative Coiled Tubing Water Shutoff Techniques in Horizontal Wells
Authors: Burov A. , Kharrat W. , Hussein N.
Published: June 2014

The wells in the southern area of Saudi Arabia are mostly horizontal wells in highly fractured carbonate reservoirs. Due to high water cut caused by water influxes through the fractures, some of these wells were dead or on intermittent production between 2005 and 2010. To increase oil production, we performed several water shutoff jobs using inflatable packers with mixed results.

The water shutoff candidate selection process starts with a reservoir and production data evaluation, followed by a coiled tubing (CT) logging run to identify the water source and adjust the required isolating fluids formulation and volume. Successful execution of the water shutoff treatment requires controlling the placement, inflation, injection, and disconnect of the inflatable packers.

Fiber-optic enabled coiled tubing (FOECT) systems, which enable real-time downhole data measurement, can optimize water shutoff treatment design, execution, and evaluation—increasing the success ratio.

For the job design, we ran production logging tools on the FOECT string to detect the water source, measure the bottomhole temperature required for the formulation of water shutoff fluids, obtain a gamma ray and/or casing collar locator (CCL) log, and get an X-Y open hole (OH) caliper critical. This helped us determine the best setting depth for the inflatable packer in the openhole section, and confirm the required water shutoff fluids volume.

The depth correlation for the packer setting was performed with a fiber-optic bottomhole assembly (BHA) gamma ray conveyed on CT. This enabled us to monitor and adjust the inflation of the packer, and the injection through it, in real time Then, the packer setting and release was confirmed with the world's first application of a fiber-optic, CT-conveyed tension and compression tool.

Recent production results showed significantly higher production with no more than 10% water cut. The integrated CT solution proved to be an effective water shutoff technique in these horizontal wells, and has potential to bring many wells around the world back to economic production.
Innovation and Successful Application for Calcium Sulfate Scale Removal in Gemsa Oil Field: A Field Study
Authors: Hamdy E. , Fahmy M. , Faramawy A.
Published: June 2014

Water flooding is the hinge pin for Gemsa Oil Field. Water injection is supplied from shallow water supply wells. Compatibility tests had indicated probable deposition of calcium sulphate scale on surface and subsurface production equipment. Calcium sulphate scale has been recognized to be a major operational problem. The bad consequences of scale formation comprised the contribution to flow restriction thus resulting in oil and gas production decrease. The nature of calcium sulphate scale is very hard and can’t be dissolved with known dissolver. Sister companies that has similar problem were always going to the mechanical remover options.

Extensive lab and field work was conducted to determine the suitable chemicals to dissolve calcium sulphate scale.

This paper describes the development and field application of chemical treatment to remove scale in an offshore 8" production line in Gemsa oil field. Continuous precipitation of calcium sulphate scale caused partial plugging of the pipeline. This partial plugging created a back pressure on production wells which decreased the productivity. The field production has been decreased to almost one tenth of the normal field production level1.

A thorough investigation was conducted to identify the composition and location of the scale, in order to recommend a suitable chemical to remove the scale, and to assess the effectiveness of the treatment method in the field.

Based on extensive lab studies, SAG-01 was tested and applied in production line to remove the scale efficiently, the program was designed taking into consideration the nature of the scale.

The treatment program included three - staged process: The use of an organic solventThe main treatment (SAG-01).The post flush stage (injection water),

The job results were outstanding, where as Production increased by about 2,000 BOPDLauncher pressure dropped by about 350 psi.Decrease the back pressure on our producing wells.Additional producing wells into production.Efficient cost /Bbl.
Experience of Multiphase Flow Measurement Systems Aapplication in Arctic Conditions
Authors: Lomukhin Alexander , Rymarenko Konstantin
Published: June 2014

Problems of well production monitoring, flow assurance and control over excavation of resources stand especially serious in harsh Arctic conditions. In case of such difficulties as gas-condensate-oil saturation, high areal and vertical heterogeneity of the reservoir and essential reservoir overpressure strong needs in individual well productivity monitoring appears. This is the only approach to optimize reservoir development properly. Continuous online monitoring of fluid flow from the reservoir to refinery facility allows avoiding hydrate formation and wax-asphalten deposition, so prevent production losses.

Now days several gas-condensate fields are under development in Russia. But the only technology recommended by licensing authority for the CGR metering is a large well testing separator. This recommendation has been brought out in 70s years of previous century. Large separators are quite dangerous by nature, cannot be fully automated, and must be equipped with additional heating devices and need expensive maintenance in Arctic conditions.

On the license blocks belonging to Rospan International- a TNK-bp company- compact and highly-mobile non-separating multiphase flow metering technologies are being tested and improved. This paper is about more than four years experience of usage of Schlumberger Vx PhaseTester. Also Vx technology enhancements for gas- condensate wells done on Rospan International fields are described. Metrological studies of multiphase flow meters were also done before. Such studies are being carried out by Rospan International in collaboration with service companies- some of the results are published in this paper.
Near Wellbore Streamline Modeling: Its Novelty, Application, and Potential Use
Authors: Skinner J. H. , Johansen T. E.
Published: June 2014

Over the last 25 years streamline modeling has proven to be a valuable technique within the field of reservoir engineering, primarily with respect to heterogeneous reservoirs undergoing convection dominated flows. To date, most applications have been performed on a full field level. In this research, streamline modeling is applied to individual wells on a near wellbore scale. The stability of the technique is achieved via first principle modeling using a time of flight algorithm in cylindrical geometry utilizing logarithmic grid refinement. The modeling technique allows for an understanding of how near wellbore heterogeneities affect flow distribution and production. The model is expanded to evaluate various completion strategies, including a cased and perforated well with associated perforation and formation damage, as well as an open-hole completion with partial filter cake build-up.

To analyze the models, response surface methodologies are utilized. With respect to a cased and perforated well, the most statistically influential factors on both flow rate and skin are perforation permeability, number of perforations, damage zone permeability, damage zone radius, and perforation length, respectively. Various interactions are also significant, including perforation permeability with perforation length and damage zone permeability with damage zone radius. In relation to partial filter cake removal in anopen-hole completion, only the area/angle of coverage has a significant effect on the productivity of a well.

The model contains numerous simplifying assumptions, including single phase incompressible flow in two dimensions for heterogeneous medium. Nevertheless, it has proven to provide stable and reliable results. Although implemented in two dimensions, the techniqueremains very useful in evaluating completion strategies and overall effectiveness, thereby offering significant potential to increase industry profitability. It is emphasized that an extension to three dimensional problems is straightforward since the third dimension is linear along the well trajectory.

Further research incorporating the works of streamline modeling in Cartesian geometries will lead to a reduction in the simplifying assumptions, allowing for compressible multiphase flow and the inclusion of gravitational effects.
Milling Low-Side Casing Exit Windows In Horizontal Wells: A Case Study
Authors: Hogg Cliff , Barker Ron , Valverde Penangos Juan Carlos , Caceres Leon Rodrigo , Gandara Carlos Alberto , Ortiz Prada Everardo , Gil Chipatecua Paola Adriana , Rueda Henry
Published: June 2014

In order to access additional reservoir, Hocol S.A. recently sidetracked out of a well located in the Ocelote Field, Colombia. The optimum path for the new well trajectory required exiting from the low side of the cased mainbore in a horizontal section of the existing well. Additionally, the proposed drilling assembly would utilize a Rotary Steerable System (RSS) in order to best reach target reservoir. Both of these requirements created additional challenges to the operator when designing a reliable casing exit operation.

The RSS, which requires rotation along the length of the drill pipe, created concern due to the sidewall loading forces at the junction point which could have potentially impeded both downhole bit performance and drill pipe life. Meanwhile the desire for a low side casing exit in a horizontal wellbore generated concern that gravity would enable the whipstock to sag towards the low side of the casing and potentially interfere with drilling assembly trips through the window and into the lateral open hole. The operator sought out solutions that addressed both of the issues while still providing field proven casing exit techniques. The technology ultimately selected by the operator involved a casing exit system with a longer whipstock face therefore providing a longer casing exit window and reduced dog leg severity through the junction area. Additionally, the chosen whipstock system provided a patented "fulcrum design" to actively lock the whipstock assembly against the casing wall and away from the low side casing window in horizontal installations.

This paper provides background information on the Ocelote Field and the drivers behind this sidetracking project. The design and operational challenges created by the desired drilling program are discussed along with a further description of the specific design problems encountered including the chosen installation equipment and techniques that addressed these challenges. Finally, the actual installation process along with problems encountered and successes achieved is covered.
Modeling for MPD Operations With Experimental Validation
Authors: Landet Ingar Skyberg , Mahdianfar Hessam , Ulf Jakob F. Aarsnes , Pavlov Alexey , Aamo Ole Morten
Published: June 2014

Heave motion of floating rigs complicates the control of pressure in MPD. During connections, the drill string is detached from the draw-works and moves with the heaving rig, causing downhole pressure fluctuations. As a step towards designing control schemes to actively attenuate the fluctuations, a fit-for-purpose mathematical model of well hydraulics is derived based on a finite volumes discretization. The model incorporates various MPD operations, including circulating in new mud, vertical motion and rotation of the drill string. Using field data from UllRigg - a full-scale experimental drilling facility - the model is validated with respect to the different MPD operations. Since an automatic control scheme in principle inherits the complexity of the model on which it is based, it is of great importance to develop models of minimal complexity. It is shown by simulations that significantly reduced order models obtained by applying the method of frequency-weighted balanced model reduction to large models outperform those obtained by simply reducing the number of control volumes. This result is particularly important for the dynamics involved during heave, since a significant number of control volumes are required to model this case. The contributions of this paper enable development of control systems for automated MPD operations from floaters.
Investigation of Sand Production Onset: A New Approach Based on Petrophysical Logs
Authors: Alipour Tabrizy Vahid , Mirzaahmadian Yaser
Published: June 2014

This paper pertains to prediction of elastic rock parameters and sanding problem onset based on petrophysical logs as a novel in-situ method. The paper addresses two main parts. In the first part, petrophysical evaluation of well log data is coupled to the Mohr-Coulomb failure criterion to predict the critical well bore pressure. Mathematical modeling is performed to demonstrate the application of well logs for prediction of sanding problem onset. In the second part, two sets of well log data from fields A and B in the Barents Sea (Norway) are used to show the applicability of the method. It has been shown that the critical well bore pressure for the Tubåen formation in field A is negative indicting the low possibility of sand production while in the field B, the critical well bore pressure is positive for the same formation. The sanding problem in field B has been observed during production and confirms the validity of the method. The different behavior of the two case studies can be linked to the packing of sand grains and cementation due to the burial depth and considerable overburden pressure. The presence of hydrocarbon and water in field B results to the diversity of sonic travel times and the rock elastic parameters compared to the corresponding data of the field A where the formation fluid is only water.
Long-Term Proppant Performance
Authors: Raysoni N. , Weaver J.
Published: June 2014

The hydrothermal degradation of alumina-based proppants, which can lead to significant loss of fracture conductivity, has been the topic of recent papers. Most of these studies were necessarily compromised by being performed on either too short of a time scale to produce geochemical effects or by using unrealistic temperature conditions to accelerate the geochemical reactions. Those studies, however, provided insight that geochemical reactions likely occur during production from hydraulically generated fractures and gave evidence of possible long-term proppant instability.

This paper presents proppant-pack permeability and proppant crush-strength data collected from a selection of hydrothermal tests performed in sealed test cells packed with proppant and formation material with no flow and no mechanical closure stress. Long-term proppant performance was determined by evaluating the proppant after 0, 25, 45, 60, 90, and 180 days of hydrothermal exposure at 300 and 450°F, resulting in verification that proppants continuously degrade with time at all temperatures. A typical long-term proppant-testing result was 80% loss in proppant-pack permeability and 40% loss in proppant crush strength with just 180 days exposure at 300°F at typical reservoir pH. These tests were performed both with and without formation material present to demonstrate the impact of reservoir/proppant compatibility. Scanning electron microscope (SEM) and energy-dispersive X-ray spectroscopy (EDX) analyses verified that dynamic molecular rearrangement occurs over the entire temperature range; albeit, at an accelerated rate as temperature increased. Extensive effort to quantify both the accuracy and repeatability of testing procedures used in this study were made and will be presented. This involves measurement of pack permeability using water before and after hydrothermal exposure, and single- proppant-grain crush-strength determination using Weibull statistical analyses.

This paper presents substantial data to support the importance of proppant compatibility when selecting the best proppant for long-term fracture conductivity. And it suggests that methods in addition to API crush and conductivity procedures need to be developed and implemented to properly rank proppant performance.
Collaborating on Real-Time Geomechanics across Organizational Boundaries
Authors: Magini L. , Molteni D. , Zausa F. , Fardin N. , Pausin W.
Published: June 2014

Real-time geomechanics techniques contribute to managing the risks and challenges faced during the realization of a well, providing, in particular, decision-making support to drillers for managing the safe mud-weight window and wellbore instability and for bridging knowledge of the rocks’ mechanical properties to drilling practices. Wellbore instability is often not caused by geomechanical conditions alone and is, in many cases, caused by the combination of geomechanics and the drilling process.

This paper describes the application of real-time geomechanics to a remote exploration project located in a challenging field and how operations benefited from this technique. A previously drilled well in the field presented serious wellbore instability issues during tripping. The instability was suspected to have caused problems during the wireline logging phases, which made it impossible to complete the formation evaluation program. The stakeholders were based in four different locations: the rig site, the operator’s office, the operator’s real-time center and the service company’s real-time center. Interaction among stakeholders was coordinated through the operator and service company real-time centers. The use of available infrastructure and remote collaboration software created a collaborative environment that successfully supported the operator’s decision-making process, with the following specific achievements: well total depth selection based on maximum allowable equivalent circulation density before incurring in losses; avoidance of wellbore instability events during drilling, tripping or logging phases; and first operator to achieve successful wireline fluid sampling in the deeper formation of this field.
Integrated Drilling, Completion, and Stimulation Approach Facilitates High-Productivity Horizontal Well with 10,000-ft Pay Interval
Authors: Jorden John , Jackson Alfred , Al Marzouqi Mohamed Abdulla , Keller Stu , Shuchart Chris , Ivan Catalin , Phi Mike
Published: June 2014

A maximum reservoir contact (MRC) well with a 10,000-ft horizontal completion interval and a 20,000-ft measured depth was recently drilled and completed in a major carbonate oil field offshore Abu Dhabi. This paper will describe the integrated drilling, completion, and stimulation approach taken for planning and executing this well. The well is completed with 38 inflow control device (ICD) subs containing 55 ICD nozzles along with 16 swellable packers. The placement of the packers and ICDs was based on reservoir inflow modeling and advanced acid modeling to ensure that adequate stimulation could be achieved through the ICDs. A specially-formulated drill-in fluid containing a pH-activated filter-cake breaker was used to minimize formation damage. To fine tune the ICD settings and locations, reservoir pressures were measured along the open hole using a formation-pressure-while-drilling tool. The 10,000-ft, 6-5/8-inch completion liner was run to TD without difficulty. A tapered drill string was run inside the liner and stabbed into a pre-installed permanent packer located in the shoe joint of the liner. The breaker system was activated by circulating a weak acid through the drill string inside the liner. To facilitate future stimulation through the ICDs, a plug was pumped through the drill string and landed in a profile located in a short tail pipe attached to the permanent packer. The well has been put on production and is one of the best producers in the field. Production logging tool (PLT) data indicate that the entire 10,000-ft completion interval is contributing. Although further analysis is ongoing, the preliminary evidence suggests that little or no formation damage was caused by the drilling and completion process. This paper points out the importance of an integrated drilling, completion, and stimulation approach for planning and executing MRC wells in carbonate reservoirs.
Understanding How the Placement of an Asymmetric Vibration Damping Tool Within Drilling While Underreaming Assemblies Can Influence Performance and Reliability
Authors: Kabbara Alan , McCarthy John , Burnett Timm , Forster Ian
Published: June 2014

This paper describes the work, on test rigs and full-scale drilling rigs, carried out with respect to placement of an Asymmetric Vibration Damping Tool (AVDT) within drilling while underreaming operations.

An AVDT, by virtue of the forward synchronous motion imposed on the drill string, offers benefits in minimizing down hole vibration related tool failures and therefore maximizing ROP. Of interest in using the AVDT is the tendency to minimize stick slip by means of the parasitic torque it generates. This is of particular importance during underreaming operations.

While underreaming, stick slip can result in low ROP and potentially an increased incidence of down hole tool failures. The use of an AVDT in these operations has been shown to significantly reduce stick slip.

However, due to the forward synchronous motion caused by the AVDT, there is the potential to cause eccentric wear to BHA components in the vicinity of the AVDT. If allowed to progress, this eccentric wear can cause a reduction in down hole tool life and drilling performance. Eliminating eccentric wear would be beneficial in reducing repair costs, extending component life and further improving drilling performance.

To minimize eccentric wear and maximize drilling performance, the placement of the AVDT within the bottom hole assembly is critical. This paper describes how the placement of intermediate stabilizers between the AVDT and the underreamer can minimize eccentric wear to the underreamer and the adjacent drill string due to the forward synchronous whirl induced by the AVDT.

This approach allows the full benefits of the AVDT to be recognized while reducing the potentially damaging effects of eccentric wear to other BHA components. The work has drawn upon small scale rig testing, full scale testing at the Ullrigg test facility in Norway and from real-world drilling and underreaming operations in the USA.
Efficient and Reliable Vertical Drilling of Top Holes with RSS in Deepwater GOM
Authors: Chamat Elias , Israel Riaz
Published: June 2014

The requirement for a reliable technology to efficiently drill vertical large tophole sections has increased substantially along with the number of deepwater wells. Inefficient salt drilling with mud motors and high rig spread rates were some good reasons for operators to prefer rotary steerable tools (RSS) in large-hole sections since they became available to the Gulf of Mexico (GOM) in October 2004. As the use of RSS in 26-in. and 24-in. sections is becoming more popular and deeper wells require minimum dogleg severities in top holes, the use and requirements for RSS have taken higher importance.

Deepwater wells are drilled through ultrasoft formations in the first 800 ft; additionally, surface conductors are normally set with an inclination at the shoe of 0.5° to 2°. The unconsolidated sediments and inclination at the beginning of the 26-in. section present a challenge to either hold vertical or drill directionally with mud motors and RSS. The combination of the issues resulted in difficulty to verticalize a few wells below the surface conductor.

While from 2004 to 2009 84% of the runs were successful, a major study was conducted during the drilling moratorium in the GOM to understand the environmental conditions that were the root cause of the issues described above. The investigation of 58 bit runs with 26-in. RSS performed from 2004 to 2010 in deep water were studied using advanced drilling software to understand and solve the issue of inability to drop inclination and, in a few cases, of unwanted inclination buildup. The advanced drilling software included time- and-depth based replay of the drilling operation, bottomhole assembly (BHA) tendency, BHA vibration models, unconfined compressive strength (UCS), and e-Caliper computations.

The study helped in understanding that conductor inclination and instantaneous borehole washout, in the first 800 ft below mudline (BML) due to UCS values as low as 350 psi, hinders the RSS push-the-bit pads from contacting the borehole, preventing a drop in inclination and, in some cases, allowing further inclination buildup. As this study was concluded during the moratorium shutdown, the lessons learned and best practices gathered helped to optimize BHAs, drilling parameters, and drilling practices. Implementation of these allowed all 26-in. RSS runs made post-moratorium to deliver vertical well intervals.
Data Aggregation and Drilling Automation: Connecting the Interoperability Bridge between Acquisition, Monitoring, Evaluation, and Control
Authors: Sadlier Andreas , Laing Moray , Shields John
Published: June 2014

Although the oil and gas industry continues to progress with drilling automation, technical challenges remain and must be addressed before this vision can become a reality. One of these challenges is the data aggregation between operators, service companies, drilling contractors and equipment manufacturers. Automation requires that the system not only control sub processes, it must also enable more complex intelligent systems to plan and react to real-time evaluation criteria and respond to predictive intelligence in real time. Data from control systems such as top drives, and evaluation systems such as downhole logging while drilling (LWD) sensors, must be aggregated in a meaningful way so it is portable, contextual, and actionable. Consider controlling the rate of penetration (ROP) based on predictive analytics assessed from formation evaluation (FE) data provided by an LWD sensor. To achieve this, intelligent control and evaluation systems must monitor and exchange information and events within a single, shared perspective.

In this paper, we review several technologies currently in use throughout the drilling industry— WITS, WITSML, OPC and PROFIBUS—and present case studies describing the current roles these technologies play and the problems they solve. The authors then analyze the limitations between these interoperable systems and associated barriers in achieving the drilling automation vision.

This paper recommends defined goals for the data aggregator and identifies existing challenges surrounding its deployment in current drilling automation environments. The authors also provide recommendations for how the industry should proceed with the implementation of data aggregation for automation. These recommendations ensure drilling automation becomes more than simple process mechanization, but advances towards intelligent systems that transform plans into reality and optimize performance and cost.
A New SBM for Narrow Margin Extended Reach Drilling
Authors: Lee John , Cullum Daryl , Friedheim Jim , Young Steve
Published: June 2014

Extended Reach Drilling (ERD) wells drilled nowadays can reach a step-out of 10 km (33,000 ft) and thus present many drilling challenges, including torque and drag, hole cleaning, wellbore stability, equivalent circulating density (ECD) management, lost circulation management, just to name a few. These challenges can severely limit the desired well depth or increase the operation time, particularly in deepwater environment. A new synthetic-based flat rheology drilling fluid (SBM) with new emulsifier and rheology modifier package has been designed for narrow margin ERD wells.

This newly developed flat-rheology SBM utilizes a novel, single emulsifier to simplify fluid formulation, improve emulsion stability, enhance thermal stability, and provide surface wetting and fluid lubricity. This allows the system to be formulated for any ERD applications with mud weights up to 18.0 lb/gal and temperatures up to 350°F. In addition, the system uses a new rheology modifier that provides temperature-independent rheology profile for better hole cleaning, barite suspension, ECD management and lost circulation control.

A recent field trial conducted in deepwater GoM indicated that the new system is easy to handle and provides good fluid performance in terms of drilling rate, ECD management, lost circulation control and hole cleaning. The SBM at one time was severely contaminated due to salt water flow but the fluid held together without any problems. Similar results on drilling performance were observed with another onshore field trial that used a non-synthetic-based fluid.

This article describes the new flat-rheology SBM system with examples showing typical mud formulations, fluid properties, barite sag performance data, field test data and computer hydraulics simulation of ECD impacts.
First Successful Rigless Acid Tunneling Job in Mauddud Carbonate Reservoir in Raudhatain Field, North Kuwait
Authors: Ashkanani F. , Sharma S. S. , Al-Ajmi M. , El-Daoushy A. , Saleh I.
Published: June 2014

RAMA-Pilot1 is a Mauddud open-hole well which is located in Raudhatain field-North Kuwait. The well had a barefoot completion and it was producing on ESP. Due to low rock quality, the well was performing less than expected levels.It was selected as an acid tunneling pilot for this project to create tunnels and new pathways inside the open-hole section. This is to increase reservoir contact, improve well productivity & eventually increase the near wellbore deliverability.

Two tunnels were created successfully inside the open-hole section and the results indicated that the productivity index increased by 3 times from 1.3 to 3.87 bpd/Psi.

This successful job was also possible from the lessons learnt, from an earlier attempt of acid tunneling in an Effluent Water Disposal (EWD) well. The job was not successful, and subsequent failure analysis of the job showed an "undersize tool in an oversize hole". So this time sufficient care was taken to measure the hole size properly to size off the acid tunnel tool accordingly.

RAMA-Pilot1 success had not only lead to restore & increase wellproduction, but it would also pave the way to enhance oil production and opening up possibilities for field wide applications especially in low PI carbonate reservoir wells. Also, it is considered for improving EWD wells performance by this technique.

RAMA-Pilot1 is the first "dendritic" well with extensive wormholes created by acid tunneling for maximum reservoir contact. The whole effect is aptly demonstrated by the change in PI of thewell before and after the acid tunneling as mentioned before.

This technique can be planned for any type of wells (EWD, oilwell, water injector) provided there is an open hole and tunnel that is created will be stable.

Econimically, acid tunneling technique compares favorably with alternative stimulation options in both time and money savings.
Double-Emulsion Spacer Design for Highly Efficient Invert Emulsion Displacement
Authors: Lu S. , Foxenberg W.
Published: June 2014

The wellbore displacement is a necessary and critical step toward subsequent completion operations and production. A successful displacement process saves significant rig time, cuts disposal volume, reduces fluid contaminations and provides the best opportunity for a successful completion. Traditionally, a displacement train typically has multiple cleaning spacers, including a solvent spacer and a surfactant spacer. It is highly preferred to have a cleaning spacer to achieve the desired wellbore cleanliness as a single stage and with minimum circulation volume. Surfactants, solvents and emulsions are used in the cleaning spacer(s) for displacement of invert emulsion drilling fluids (IEF). The spacer system is selected depending on the displacement requirements and wellbore conditions. This paper describes innovative double–emulsion technology that shows highly efficient and effective performance in IEF displacement, as the design fully combines the power of both surfactants and solvents.

This paper presents theoretical and lab testing results for fundamental understanding of IEF film removal from metal surfaces under various conditions. It was found that the solvency and surfactancy play different roles during the film removal process. A macroemulsion or microemulsion contains both solvents and surfactants but they often have a limited operational window with reduced solvency and surfactancy. Based on the analysis described in this paper, an innovative double-emulsion system was developed to fully preserve the solvent cleaning power and dispersive and water–wetting power of surfactants. It has a unique water-in-oil-in-water structure, in which the dispersed solvent droplets contain smaller droplets of a second aqueous phase. The solvent droplets effectively remove the top layer of mud film and directly deliver the surfactants to the metal surface. This technology has been applied in various successful field applications.
A New Outlook on the Ideal Packing Theory for Bridging Solids
Authors: Chellappah K. , Aston M.
Published: June 2014

Carefully engineering the size distribution of bridging solids should enable us to form filter cakes of low permeability. A theory called the ideal packing theory is commonly used to blend bridging solids which suggests the ideal blend of particles should follow the relationship cum vol% ∝ dx. The aim of this work was to experimentally assess this theory. Investigations were carried out to determine if there is an x value which gives a better fluid loss performance than the typically-used x = 0.5.

The results suggest that selecting x ~ 1 could be more appropriate than using the conventional x = 0.5. The physical meaning when x = 1 is that there will be an equal volume of particles of each size within the distribution; i.e. the distribution is linear. In addition, the results also showed that a blend with a broad size distribution gave a lower fluid loss than a narrow distribution, even when the narrower distribution consisted of finer particles. The trend was that filter cakes of decreasing permeability were formed as x increased from 0.1 to 0.5. Further increase in x up to 1.25 did not appear to have a prominent effect, while further increases beyond 1.25 appeared to increase the filter cake permeability. Trends were similar for filter cakes formed on filter paper and on simulated rock material.

Particle blending is important for the selection of bridging solids for drill in fluids, and also for wellbore strengthening (stress cage) applications. Conventional ideal packing theory has been widely used but a review of this theory backed up by laboratory checks has been overdue. This work should aid in the development of a more consistent approach to the selection of the optimum blend of bridging material for a given application.
Compatibility and Phase Behavior Studies Between Corrosion Inhibitors and Surfactants-Based Acids
Authors: Li L. , Nasr-El-Din H.A. , Zhou J. , Holt S.
Published: June 2014

A good surfactant-based acid should have the following properties: thermal stability, compatibility with cations, low viscosity in live acids but high viscosity in spent acids, ease to be removed by internal or external breakers, and no harm to the environment. Corrosion inhibitors must be added to the acid system to protect well tubulars and minimize the Fe contamination. The components of corrosion inhibitor usually contain short-chain alcohols (e.g. isopropyl alcohol) that can significantly affect the properties of surfactant-based acids. Therefore, corrosion inhibitor plays an important role in evaluating acid systems.

Two amine oxide surfactants (S and SW) were examined in this work. The composition of the surfactants was similar, but there was more 1,2 propanediol in surfactant SW. Three corrosion inhibitors (A, B, and C) were tested and all of them contained a certain amount of propargyl alcohol. However, there was a larger amount of isopropanol in corrosion inhibitor A, and more butanol in corrosion inhibitor B. A HPHT rheometer was used to measure the rheological properties (viscosity, G’ and G") of surfactant-based water system, live and spent acids from 75 to 300oF at 300 psi.

The results show that the addition of corrosion inhibitor to spent acid significantly reduced its elastic (G’) and viscous modulus (G’’). The maximum temperature that these two surfactants can be used was 220°F. Compared to surfactant-based acids made with corrosion inhibitor B or C, the acids with corrosion inhibitor A showed a much higher viscosity, but phase separation was observed after heating to 300°F. Although corrosion inhibitor B was compatible with surfactants, it adversely influenced the rheological properties of acids. If corrosion inhibitor C was used, the system with surfactant SW can be effectively used at temperatures above 150oF; whereas acids prepared with S1 can be efficiently applied at lower temperatures (<150°F). Cryo-TEM studies showed that corrosion inhibitors affected the rod-like micelle network, which caused the reduced apparent viscosity. Results of this work can be used to better select acid additives to maximize the performance of amine oxide-based acids.
Analysis of Parameters Affecting Critical Flow Rate in a Horizontal Well: Case Study in Ahwaz Oil Field
Authors: Goodarzian S. , Ghalambor A. , Izadi M.
Published: June 2014

Horizontal well is a solution to accomplish higher production in thin reservoirs or those with very low permeability. However, these wells suffer from early water and gas conning and this jeopardizes the life of the well and its productivity. Therefore, having an understanding of the conditions in which coning occurs is highly desired. In this study several rock and fluid properties which affect water or gas breakthrough will be investigated and a few correlations are proposed to determine the breakthrough time and critical flow rate for the well in question. Ahwaz oilfield is one of the giant fields in the world and the reserves are estimated at more than 40 billion barrels. The reservoir is extremely heterogeneous latterly and vertically. Reservoir studies indicate that horizontal drilling is the best solution to increase ultimate recovery. However, the water and gas coning is the main problem in this field and several reports have shown the severity of this issue. A simulator has been written in FORTRAN to investigate the sensitivity of various parameters on well productivity and water breakthrough.

The study shows that when the formation volume factor increases by 0.1 bbl/STB, the well productivity decreases by 2480 STB per day and also the water breakthrough time increases. In this paper it has also been shown that the reservoir under study with high permeability is not performing efficiently using horizontal wells since having high production in early times does not guarantee higher ultimate recovery.

The dominant parameters in this case study are the horizontal well length and completion type. Using ICD (Inflow Control Device) certainly decreases the water-oil front movement towards the wellbore, and finally according to the simulation if the well had been drilled 320 ft above the water-oil contact instead of 127 ft, the critical flow rate would have been increased from 34000 to 210000 barrel per day.