bluuebunny/crossref_metadata_2025 huggingface dataset:
Oil Recovery Enhancement in Mature Reservoirs Using Innovative Horizontal Well Placement and Evaluation Strategies - An Example from South China Sea
Authors: Luo D. , Li L. , Tao B. , Denichou J. M. , Halomoan P. M. , Bisain A. S. , Wang C.
Published: September 2013

Located in offshore South China, Panyu oil field has entered into mature development phase after a decade of intensive production. A new horizontal wells campaign has resumed since 2012 targeting the remaining thin oil column reserves that are being squeezed by strong bottom water drive. The fluid contacts are highly uncertain in the current reservoir state. After a review of the technical and geological challenges encountered during the project, this paper will feature the successful approach taken to optimize remaining reserve recovery using innovative horizontal well placement strategies. The how-to-execute of these strategies will be detailed through the description of various cases encountered. This includes landing the wells with very low incident angle - less than 2 deg at the top of the reservoir - and drilling the lateral sections within a very small target window (2 ft) below the reservoir top, which both require rigorous geological well placement and control. In addition, the authors will describe how during the thorough planning phase, the team has selected to use directional electromagnetic and wellbore imaging technologies for proper well placement, reservoir profiles description, and current OWC level identification.

The team has observed that the application of these integrated strategies and technology solutions have helped to:

Eliminate the needs for pilot-hole wells and contributed to the improvement of the drilling efficiency by keeping the trajectory within the reservoir, avoid unnecessary adjustments, and avoid the sidetracks, thus significantly save the AFE budget. Minimize attic oil, thus optimizing the remaining reserve recovery. Optimize the outline of future horizontal drains locations.

The performance of the horizontal wells drilled up to date – and placed extremely close to the reservoir top – shows that each of them has produced from 2000 to 6000 bopd with zero to very low water cut. A reversing production trend from the decline to positive growth is also recorded. Six months after the first horizontal well inception in September 2012, the cumulative incremental oil of the field has reached 2.1 million barrels or 45% higher than forecast. The successful implementation of the new development strategy and the application of fit for purpose technologies in highly mature oil fields have led to sustained and extended production, increasing the ultimate recovery and asset economics.
Step Change Drilling Technology Modifies Drill String Dynamics and Results in Reduced Drilling Vibrations
Authors: Gaines M. , Morrison RD. , Herrington D.
Published: September 2013

Through the years, significant advancements have been achieved with respect to well design, depths drilled, and overall drilling efficiencies. However, in spite of all of these advancements, one major consistent challenge facing the drilling community is the prevalence of downhole vibrations, with specific emphasis on lateral vibrations and shocks.

These lateral shocks can be attributed to numerous drilling environmental challenges, and with the exponential increase in long reach laterals, well profiles, and formation changes, the increase in potential for significant shocks to cause damage to key bottom hole assembly (BHA) components is increased as well. To mitigate potential BHA damage, increase ROP, and provide a significant increase in bit life, a novel technology has been developed to tackle these challenges.

This vibration dissipation and mitigation tool has proven performance in both land and offshore applications, providing marked improvements over previous conventional solutions. When using this technology in the Gulf of Mexico, ROP improvements yielding an excess of 50% as well as a substantial stick slip reduction were observed, ultimately reducing time drilled and overall drilling costs.

The application of this innovative vibration mitigation and reduction technology is unique, especially in comparison to conventional solutions seeking to reduce vibration. Rather than seeking to simply absorb vibrations caused by drill string dynamics as with conventional solutions, this technology seeks to actively change the dynamics of the drill string to prevent these vibrations from ever occurring while offering a system for dissipating the residual vibrations. As this paper will demonstrate, this new technology has proven to successfully provide more control to the driller in applications once thought to be without a solution to such vibrational challenges.

This paper will discuss the advantages of this formative technology along with providing case history and accompanying supporting run data to quantify the performance of this innovative technology.
Magnitude-Based Calibrated Discrete Fracture Network Methodology
Authors: McKenna Jonathan P.
Published: September 2013

Effective propped fracture half-lengths following a typical hydraulic fracture stimulation of a wellbore can be difficult to quantify. Therefore, new modeling techniques must be developed to make estimates of proppant distribution in a formation to understand the spatial extent of proppant-filled fractures. The distribution of propped and unpropped fractures can then be statistically analyzed to determine the productive stimulated rock volume (SRV) and constrain key field development parameters such as wellbore and stage spacing as well as vertical containment of proppant placement.

A magnitude-based calibrated Discrete Fracture Network (DFN) methodology based on microseismicity induced during stimulation of a wellbore has been developed that incorporates magnitude of the event (and associated microseismic moment (M)), rock rigidity (μ), injected fluid volumes (Vi), and fluid efficiency (η). Calculated fracture volumes (Vf) are then scaled to account for any missing portion of the seismic population. The calibrated DFN can then be filled with the measured injected proppant volume on a stage-by-stage basis by initially filling fractures nearest the wellbore and systematically filling fractures outward from the wellbore until all deposited proppant volumes have been depleted.

Fundamentally, for every microseismic hypocenter, fracture area (A) =M/μδ where δ is displacement along the slip plane. Since δ is not directly measured, it is initially estimated using an empirical relation as a function of M and corrected using a scaling factor (k) where k=Vf/[(Vi)η]. The scaling factor is calculated by comparing Vf to (Vi)η following a hydraulic fracture stimulation of an individual stage where the sum of the seismic moments is greatest (compared to all stages monitored) and energy released is only associated with fluid injection (e.g. not tectonic activity).
Modeling Low Salinity Waterflooding: Ion Exchange, Geochemistry and Wettability Alteration
Authors: Dang Cuong. T. , Nghiem Long. X. , Chen Zhangxin , Nguyen Quoc. P.
Published: September 2013

Low salinity waterflood (LSW) has become an attractive enhanced oil recovery (EOR) method as it shows more advantages than conventional chemical EOR methods in terms of chemical costs, environmental impact, and field process implementation. Extensive laboratory studies in the past two decades have proposed several pore-scale mechanisms of oil displacement during LSW flooding, which are still open for discussion. However, the capability of reservoir simulators to model accurately this process is very limited. This paper provides a critical review of the state of the art in research and field applications of LSW. The focus is on a widely agreed mechanism that is the wettability alteration from preferential oil wetness to water wetness of formation rock surfaces. Ion exchange and geochemical reactions have been experimentally found to be important in oil mobilization due to enhanced water spreading at low salinity. To evaluate the significance of this surface wetting mechanism, a comprehensive ion exchange model with geochemical processes has been developed and coupled to the multi-phase multi-component flow equations in an equation-of-state compositional simulator. This new model captures most of the important physical and chemical phenomena that occur in LSW, including intra-aqueous reactions, mineral dissolution/precipitation, ion exchange and wettability alteration.

The proposed LSW model is tested using the low-salinity core-flood experiments reported by Fjelde et al. (2012) for a North Sea reservoir and the low-salinity and high-salinity heterogeneous core-flood experiments by Rivet (2009) for a Texas reservoir. Excellent agreements between the model and the experiments in terms of effluent ion concentrations, effluent pH, and oil recovery were achieved. In addition, the model was also proved to be highly comparable with the ion-exchange model of the geochemistry software PHREEQC for both low salinity and high salinity (Appelo, 1994). Important observations in laboratory and field tests such as local pH increase, decrease in divalent effluent concentration, mineralogy contributions, and the influence of connate water and injected brine compositions can be reproduced with the proposed LSW model. Built in a robust reservoir simulator, it serves as a powerful tool for LSW design and the interpretation of process performance in field tests.
Reducing Drilling Costs Through the Successful Implementation of a One-Run Monobore Well Strategy
Authors: Beaton Tim , Veloso Ryan , Kowbel Kevin , Specht Leo , Afseth Chris , Herman J. J.
Published: September 2013

As horizontal drilling programs continue to proliferate across the industry, and new technologies and operational practices are developed and advanced, the reality of a one-run well has emerged. In various applications across several provinces in Western Canada, the ultimate goal of drilling a horizontal well in one run from surface casing has been realized. This success comes as a function of the combined effort of the operator, directional drilling company and PDC bit company to solve the multitude of technical challenges facing a monobore strategy in areas with hole stability issues.

While many horizontal applications are now utilizing a monobore (one hole size) well plan below surface casing, the vast majority of those applications have one critical aspect in common - the upper hole sections are in very stable formations that can be left open for long periods of time. This is a critical aspect due to the fact that nearly all horizontal wells require multiple bits and multiple BHA configurations to reach total depth (TD). In areas where hole stability is an issue, an intermediate hole section is typically included in the well plan to seal off the unstable formations to allow the lateral interval of the well to be completed. In addition to the added time and costs required to set an intermediate string of casing, this type of well plan also results in a smaller hole size in the horizontal section.

In order to complete a horizontal monobore well through unstable formations, the well must be drilled in a very short period of time and must be drilled with excellent hole quality to eliminate any issues with rapidly completing the wells. This paper will detail a variety of these types of applications that successfully reached TD in 4-6 days from surface casing and were completed without problems.

This rapid monobore well approach leads to both huge cost savings for the well and a larger hole size in the reservoir for improved production. The result is more economical wells, drilled in much less time than conventional wells that yield greater returns.
Insights From History Matching and Forecasting Work for a Steeply-Dipping, Faulted Volatile Oil Reservoir
Authors: Kaul Sandeep P , Ambastha Anil , Eme Vincent , Creek Jefferson
Published: September 2013

History matching and subsequent forecasting work becomes a challenging task if limited supporting production data is available and the reservoir is severely depleted. For an offshore, volatile-oil reservoir, added to this challenge was an uncertainty in fluid PVT, where the data clearly suggested presence of condensate, but with black-oil properties. The permeability distribution from logs was counterintuitive to the production data from the wells. The reservoir had a structural relief in excess of 1000 ft., most likely having API gradient, but both the API and the GOR data indicated that there were possible errors in measurement. There was uncertainty associated with original oil-water contact also. The production data showed the reservoir to follow primarily a classical solution gas-drive response, but simple material balance analysis proved a weak aquifer effect as well.

The approach followed in simulation was the process of elimination. Pressure match was first achieved, but questions remained about its robustness around the main sealing fault. GOR was targeted next and several different condensates and one full compositional fluid model of a nearby reservoir were unsuccessfully tested. For matching the historical gas production, a new high condensate yield fluid PVT was used. The idea of another oil-water contact (OWC) was tested in the saddle of the reservoir to account for most likely early water breakthrough in a well there. The secondary gas cap formation and its effects were crucial in achieving satisfactory history match.

The confidence in the history match, as having captured the physics of the flow, led to forecasting scenarios which were not possible with a black-oil model. Most of the data was found not to be erroneous. What was needed was judicious data interpretation to achieve satisfactory history match. To produce these kinds of depleted, faulted reservoirs further, a strategy to better manage the evolution of secondary gas cap was of utmost importance.
Newtonian Fluid in Cementing Operations in Deepwater Wells: Friend or Foe?
Authors: Khalilova Polina , Koons Brian , Lawrence Don Woody , Elhancha Anouar
Published: September 2013

Cementation of wells, especially in deepwater has attracted a great deal of attention after recent loss of well control events and subsequent changes in regulatory requirements with respect to achieving effective zonal isolation, preventing the release of wellbore fluids to the environment and avoiding the need for cement job remediation[1, 2].

Deepwater well construction presents unique challenges for proper cementation. These challenges are driven by the greater complexity of deepwater (DW) wells. There is; narrower pore pressure (PP) and fracture gradient (FG) margin, use of oil based mud (OBM) or synthetic based mud (SBM) drilling fluid that is incompatible with water based cement slurries, additional length for the cementing fluids to travel due to the sea water depth increasing the risk of intermixing between fluids, technology pushed to the limit, and the cost of drilling in deepwater that is much higher than conventional wells.

Currently there are two main flow regimes used when planning for effective mud removal and cement placement: effective turbulent flow and effective laminar flow. Turbulent flow is generally considered the preferred method of efficiently removing fluids; however there are a number of requirements to be met in order for turbulent flow to be both safe and effective. Laminar flow is the most widely used due to the ease of placement design and the lower annular velocities required to achieve effective cement placement. Drilling fluids, weighted spacers and cement slurries can all be designed in effective laminar flow, since they exhibit a yield stress. Brines, water, and chemical washes are typically designed in effective turbulent flow.

In this paper the authors will discuss the factors to be taken into account when designing cement jobs using fluids in turbulent flow and some of the overlooked benefits of using turbulent flow design for mud removal. Case histories from DW wells cemented in the Gulf of Mexico region and risk factors will be discussed. It will be demonstrated that when designed and executed properly, the use of turbulent flow mud removal with Newtonian fluids can be beneficial in DW cementing operations.
A New Approach for Build Rate Estimation of Downhole Motors
Authors: Marchand Nicholas , Kalantari Masoud
Published: September 2013

Build rate prediction is a critical element in downhole drilling and proper BHA design. This paper presents a simple build rate prediction method that demonstrates improved accuracy for short bit-to-bend (SBTB) motors compared to the industry standard method.

The Three-Point Geometry method is the industry standard to calculate the predicted build rates of downhole motors. While this method provides reasonable results for conventional motor designs, it consistently fails to match with field data for SBTB motors. Field reports clearly demonstrate that SBTB motors can achieve significantly higher build rates than predicted by the three-point geometry calculations.

A new analytical method has been developed to predict the build rate of conventional and SBTB motors. The new method assumes that as the bit advances, it will drill in the direction it is pointing so that the resulting curved path is tangent to the inclination of the bit. Based on this bit-tangency assumption and a defined upper contact point, the predicted hole curvature can be calculated for a given motor configuration.

Results from the Bit-Tangency method provide a more accurate indication of the increased build rates that SBTB motors can achieve. Further, the results of the new method for conventional motors conform to field data and the three-point geometry results. Hence, the Bit-Tangency method can replace the standard Three-Point Geometry method of build rate prediction for both conventional and SBTB motors.
Multiple Well Deconvolution
Authors: Cumming J. A. , Wooff D. A. , Whittle T. , Gringarten A. C.
Published: September 2013

In well test analysis, deconvolution is used to transform variable-rate pressure data into a single constant-rate drawdown suitable for interpretation. It is becoming part of a standard work flow for exploration and appraisal well test analyses and in production test analysis where there are no interference effects from nearby wells.

This paper develops and extends the single-well deconvolution algorithm of von Schroeter (2004) to the larger and more complex multiwell deconvolution problem.

To validate the algorithm, it is applied to a synthetic example with known solution and an uncertainty analysis is performed to quantify the impact of non-uniqueness on multiwell deconvolution.

The use of the algorithm is further illustrated with a field example.
Fully Rotating PDC Cutter Gaining Momentum: Conquering Frictional Heat in Hard/Abrasive Formations Improves Drilling Efficiency
Authors: Zhang Youhe , Burhan Yuri , Chen Chen , Tammineni Sandeep , Durairajan Bala , Mathanagopalan Siva , Ford Robert
Published: September 2013

A fixed PDC cutting element creates an inherent limitation because only a small portion of the diamond table contacts formation and as the cutter wears/chips, drilling efficiency declines. It is well documented that wear flats generate a high degree of frictional heat which breaks down the diamond bond and in extreme cases can even convert synthetic diamond back to graphite.

To solve the issue a research initiative was launched to investigate different methods to enable a PDC shearing element to fully rotate while drilling to increase overall cutting efficiency and bit life. Engineers investigated different retention methods and cutting structure designs to create the optimal driving force to accomplish the objective. Several designs were implemented that hold the cutter securely in place and allow full cutter rotation. These assemblies were modeled using an FEA-based system and then tested in the laboratory to evaluate function and strength. Experiments confirmed the new rolling cutter (RC) was able to shear an extended section of rock with a consistent force level (lbs). Conversely, the traditional fixed-cutter assembly required steadily increased force to drive the cutter the same distance. Examination of the rolling cutter's dull condition clearly indicated significantly improved durability and cutting efficiency.

The recent introduction of a new rolling cutter PDC bit that utilizes the entire 360° of diamond edge has delivered positive results in field trials. Initial testing was targeted at the highly abrasive Granite Wash formation in Western Oklahoma/Texas Panhandle where cutter wear is the predominant failure mechanism. Application challenges include low ROP and premature tripping for a new bit. A six-bladed prototype PDC bit was manufactured with rolling cutters strategically positioned in the shoulder area. The bit was run on a steerable motor through the horizontal interval with good results increasing total footage and ROP capabilities.

In the central USA the rolling cutter has been run more than 70 times and has increased average footage totals by 56% compared to 450 offsets drilled with conventional fixed cutter PDC bits from various manufacturers. The authors will present results of field tests and two case studies that document performance improvement in these challenging drilling environments. They will also outline plans for future development.
Case History: Recent Lower Tertiary Multi-Zone Single Trip Deepwater Completion
Authors: Joseph Kevin P. , Ogier K. Scott , Moore Ronnie
Published: September 2013

Multi-Zone Single Trip (MST) technology is used to perform sand-control treatments individually to multiple zones in a single trip. In Deepwater installations, Well Integrity, Operational Efficiency and Completion Excellence are critical success factors for overall project returns. Well integrity is accomplished by ensuring that completion components conform to the extreme downhole well conditions; that well control is present during each stage of the completion operations; and that zones are positively isolated during the high pressure frac-pack treatments. Also, well integrity needs to be maintained during the selective isolation string deployment and throughout the production life of the well. Operational efficiency is accomplished by establishing clear guidelines during the planning phase of the wells; ensuring the right personnel are involved at the right time; identifying and eliminating any possible operational risk; simplifying tool manipulations; establishing downhole tool diagnostics that enhance decision making; and finally, improving downhole tool visualization for operational clarity. Completion excellence is achieved by ensuring completion components are fit-for-purpose for the extreme high pressure and erosive environment with maximum flow areas for optimum production, built-in redundancy for flawless executions, and software modeling to simulate downhole conditions from installation through production phases. This paper is meant to show how these features were used in the most recent completion in the Cascade field and provide recommendations for similar operations while identifying areas of improvement for upcoming installations.
Comparison of the Impact of Fracturing Fluid Compositional pH on Fracture Wall Properties in Different Shale Formation Samples
Authors: LaFollette Randy F. , Carman Paul S.
Published: September 2013

Fracturing fluid compositions have historically been formulated to achieve desired rheological properties under the conditions of pump time and temperature in the subsurface. However, fluid selection best practices came into being when conventional and mixed conventional and tight-gas sandstone reservoirs dominated oil and gas operations. Those reservoirs consisted mainly of quartzose sandstones cemented by quartz overgrowths or calcite. Those rocks were relatively unreactive to water-based fracturing fluids, except for their grain-coating clay minerals. Only rarely was clay present in the reservoir rock-pore network in sufficient quantity to contribute to changes in fracture wall mechanical properties such as Brinell hardness. The changeover in the North America hydraulic fracturing market to include the shale plays has brought into question whether rheology at time and temperature should remain the dominant fluid design criteria.

Samples of Bakken, Huron, Haynesville, and Marcellus shale core material have been tested against different fracturing fluid compositional pH values for time periods up to 8 months. The shale samples were subjected to Brinell hardness measurement before and after testing with pre-test measurements being taken in the wet condition and post-test measurements being done in the dry condition. Water composition was measured before and after each test, as was proppant strength.

Results indicate that pre-and post-immersion Brinell hardness values vary from one shale sample to another. Samples having different mineral composition may have different softening response to wetting. Also, natural and man-made proppants exhibit different degrees of strength loss or retention under long-term test conditions.

This paper is significant in that it directly compares measurements related to proppant embedment potential across different shales. It also provides a series of data points to aid in choosing particular fracturing base fluid compositional pH values for treatment design in wildcat areas.
Critical Evaluation and Improvement of Methods for Determination of Matrix Permeability of Shale
Authors: Civan Faruk , Devegowda Deepak , Sigal Richard
Published: September 2013

Previously available interpretation methods developed for determination of gas permeability from crushed samples are mostly applicable for conventional porous rocks of reasonably high permeability. This paper presents an improved formulation which honors the relevant physics of fluid, transport, and shale-rock conditions for determination of extremely-low nanodarcy gas permeability of shale by pressure-pulse transmission testing of crushed shale-rock particles. The new method is demonstrated by means of typical simulated test conditions. Assuming viscous, Darcy flow instead of the nonDarcy flow yields almost twice the actual value of the intrinsic permeability for this case.
A New Finite-Element Numerical Model for Analyzing Transient Pressure Response of Naturally-Fractured Reservoirs
Authors: Doonechaly Nima Gholizadeh , Rahman Sheik , Cinar Yildiray
Published: September 2013

This paper presents a new numerical model for analyzing transient pressure test data taken from naturally-fractured reservoirs. The model computes well pressures for a single well completed in a naturally-fractured reservoir. It models characteristic properties of naturally-fractured reservoirs including fracture orientation, fracture length, fracture density and fracture distribution. A single-phase, slightly compressible fluid flow is assumed. Fluid flow is modelled based on a hybrid approach which combines single continuum (block-based permeability tensor for small to medium fractures) and flow in discrete fractures (long fractures). A sensitivity analysis is presented to examine the effects of fracture density, fractal dimension and percolation probability. Then the model is validated against two worked examples reported in the literature. Results reveal that new model can predict transient pressure response of complex naturally-fractured reservoirs. Hence, it can be used to match pressure test data and diagnose characteristic properties of naturally-fractured reservoirs.
A Comprehensive Kinetics Model for Light Oil Oxidation/Combustion Reactions under High Pressure Air Injection Process (HPAI)
Authors: Barzin Y. , Moore R. G. , Mehta S. A. , Ursenbach M. G. , Tabasinejad F.
Published: September 2013

It is acknowledged that chemical reactions and their kinetics play a major role on the success of both light and heavy oil air injection processes. Historically, Light oil reactions have been characterized mostly using conventional heavy oil kinetics models. However, sensitivity of the reaction kinetics to phase behavior and compositional changes in light oils call for a comprehensive study of kinetics of light oil oxidation. This paper provides a new and comprehensive kinetic model for light oils oxidation/combustion reactions under HPAI, through experimental studies and numerical simulation.

For the purpose of this research, a high pressure ramped temperature oxidation reactor (HPRTO) was designed. 15 air injection and nitrogen injection experiments were conducted on the mixture of light oil, water, and core. Based on the data, observations, and understandings achieved during the course of the experimental study, a reaction kinetic model was set up. This primary kinetic model was then incorporated into a thermal numerical simulation model to replicate the behavior of the conducted air injection tests. After fine-tuning of some kinetic parameters against the experimental data, the final proposed model was verified by its successful application to two other different cases.

The significant finding of this research, which is the main feature of the proposed kinetic model, was the recognition and characterization of the potential vapor phase combustion reactions during the HPAI process and incorporating them into a light oil kinetics model. The model integrates the hydrocarbon compositional changes and energy generation characteristics of the oxygen addition or so called LTO reactions. Introducing the concept of flammability range into the kinetic model and defining the flammable limits for vapor fuel mixture in this model enables accurate prediction of ignition and exhaustion of the combustion reactions in the vapor phase.

Lack of a reliable kinetics model for incorporation into field numerical simulations has been a limiting factor to the prospective vast applications of HPAI as an enhanced recovery method. The kinetics model proposed in this paper, which is supported by extensive experimental data, could successfully predict the oxidation/combustion behavior of two different light oils under the conditions associated with high-pressure air injection tests. The paper also presents a framework for application of the kinetics model to any light oil under HPAI.
Real-Time LWD Sonic Semblance Image and the Step Change in LWD Sonic Applications—A Case Study from Latin America (Mexico)
Authors: Mickael Medhat , Barnett Craig , Maranuk Chris , Nye Rebecca , Diab Mohamed , Carreira Javier Armando , Morales Victor Arreola , Batista Erika Nino , Chi Jose Edilberto
Published: September 2013

The need for reliable logging-while-drilling (LWD) sonic data in real-time has been of great interest to many operators since inception. However, providing such information reliably requires many challenging tasks. Unlike wireline tools, where waveforms are sent and processed on the surface in real-time, the waveforms of an LWD sonic tool cannot be sent in real-time due to bandwidth limitations. This requires the data to be processed downhole and only the processed data to be sent in real-time. Traditionally, windows were used to define the range of the real-time compressional velocity. However, a major drawback to this approach is the requirement of knowing the compressional arrival range beforehand and the possibility of receiving a different arrival. For example, fast shear could be confused with slow compressional data. Sending a complete semblance image in real-time is the best way of capturing all arrivals. However, data must be inelegantly compressed to maintain the arrival times yet reduce the bandwidth to a minimum. A new sonic LWD tool has been developed to provide high-quality real-time sonic semblance images, creating opportunities for obtaining this information while drilling. An offshore case study comparing the real-time sonic images to the recorded memory data in terms of resolution and data quality will be investigated. The paper will discuss the uses and applications of the sonic semblance image and its real-time value. This proven data acquisition process is crucial in allowing the end user to access all the formation evaluation data, thus improving real-time decision making.

Technological advances in LWD services have had a direct impact on the ability to evaluate a reservoir and provide production planning on a foot-by-foot basis. The amount of downhole data processing and data compression required plays a critical role in delivering real-time sonic data while drilling. High-resolution, real-time semblance images can be obtained in real-time, and are expanding the uses and applications over traditional delta-t data acquisition.

Operating companies have formed an outdated opinion that real-time LWD sonic data is unreliable and requires post-processing. With newer technology, high quality semblance images can be provided in real-time and, as a result, there is a shift in the way operating companies use the data for analysis and planning. The offshore environment has always presented a difficult challenge for acoustic tools in general; however, with the scientific advances in LWD tools, continuous compressional and shear arrival from the real-time semblance images can prove useful. This case study will also provide basic background information on the lithology in the region, highlighting why sonic data in particular was required in real-time.
The Growth of Coiled Tubing and the Benefits of Thinking Small Again
Authors: Terry Adrian , Pate Brad , Stanley Rick
Published: September 2013

Description

The development of coiled tubing as we know it today dates back to the early 1960s. It has become an integral component of many well service, workover applications and programs. While well services and workover applications still account for approximately 75% of Coiled Tubing (CT) use, technical advancements have increased the utilization of CT in both drilling and completion applications1.

In recent years the industry has been trending towards drilling deeper, highly deviated and horizontal wells. In turn this has also included larger and more complex completions. This trend has challenged the CT service providers to develop larger, more robust and innovative equipment to deploy larger CT sizes and to support increasingly difficult wellbore interventions. It is important that we understand the history behind the initial small CT units (CTUs) and pipe sizes, their limitations and the evolution to the large CTU sizes used today.

This paper describes why the industry still requires smaller, lighter CTUs and associated pipe sizes along with the benefits they offer today, particularly in offshore applications.
Interpretation of Array Production Logging Measurements in Horizontal Wells for Flow Profile
Authors: Liao L. , Zhu D. , Yoshida N. , Hill A. D. , Jin Minquan
Published: September 2013

Interpretation of production logging in multi-phase flow wells is challenging, especially for highly deviated wells or horizontal wells. Flow regime-dependent flow conditions strongly affect the measurements of production logging tools. Segregation and possible back flow of denser phases result in misinterpretation of the inflow distribution. To assess the downhole flow conditions more accurately, logging tools have been developed to overcome the flow regime related issues. Multiple-sensor array tools measure the fluid properties at multiple locations around the cross-sectional area of the wellbore, providing a distributed measurement array that helps to relate the measurements to flow regime and translate the measurement to inflow distribution. This paper present a methodology for using array data from production logging tools to interpret downhole flow conditions. The study uses an example logging tool that consists of 12 resistivity, 12 capacitance probes, and six spinners around the wellbore circumference. The method allows interpretation of phase volumetric flow rates in sub-divided cross-sectional areas based on sensor locations. The sub-divided area method divides the wellbore cross-sectional area into several layers depending on the number and arrangement of the sensors with each layer containing at least one sensor. Holdup and velocity outputs from sensors in each wellbore area segment are combined to calculate the volumetric flow rates of each phase in each segment. These results yield a profile of flow of each phase from the high side to the low side of the wellbore, and the overall flow rates of each phase at every location along the well where the interpretation method is applied.

The method developed was used to interpret the flow profile of an Eagle Ford well producing gas and water at downhole conditions. A reasonable profile of gas inflow was obtained and the profile was similar to that interpreted with a commercial production log interpretation software package. The interpretation of the water flow profile was complicated by low total water production rate and variations in wellbore inclination.
Targeted Annular Hydraulic Fracturing Using CT-Enabled Frac Sleeves: A Case History from Montana's Bakken Formation
Authors: Castro Luis A. , Johnson C. Christopher , Thacker Christopher W.
Published: September 2013

Unconventional reservoirs require innovative completion techniques and technology to become more economical. Formations vary drastically in lithology, lateral lengths, completion methods, and financial drivers. Since reservoir conditions typically mandate the use of hydraulic fracturing for economical production results, a significant amount of resources are focused on making the fracturing process more efficient and lowering its environmental impact.

This case history includes an operational review focused on a novel technique to rapidly perform targeted annular hydraulic fractures by deploying an activation tool on coiled tubing (CT) to open frac sleeves in a horizontal well. The paper covers results and information gathered from the first operation of its kind in Montana's Bakken Formation – where a total of 19 stages were fractured in the shaley dolomite.

The new technology does not involve dropping balls or setting composite plugs to isolate stages. Rather, the technique utilizes frac sleeves that are activated using a CT bottomhole assembly to save time between stages. The sleeves can be cemented in place if desired and have a full-bore internal diameter that does not require post-treatment composite plug millouts, further reducing overall completion time and time to production. Additional capabilities of the system enable the use of memory gauges to monitor downhole pressure and temperature characteristics.

The operator preferred this method due to its targeted nature, efficiency, and fluid savings. As opposed to multicluster fracturing methods (such as ‘plug-n-perf"), a single entry point during the frac job promotes increased fluid velocity, enabling a more aggressive sand ramp and reduction in required hydraulic horsepower. Similarly, the single entry point ensures that a fracture is generated at each port, as opposed to the possibility that some clusters are not treated. In addition, no composite plugs or diverting devices are required to be pumped down the wellbore, so water usage is reduced considerably. The system, already used in thousands of fracturing stages in Canada, speeds up the completion process, uses less fluid, minimizes risks, and reduces overall downtime.
Fully Mechanical 3D Rotary Steering Technology Provides Economical Alternative To Conventional Rotary Steerable Tools
Authors: Herrington D. , Mercer S.
Published: September 2013

The demands of land-based drilling have evolved in recent years, requiring the drilling of complex, extended reach, horizontal wellbores to cross multiple production zones as well as to optimize the production of unconventional plays. Rotary Steerable System (RSS), technology is now being applied to enable drillers to meet today's directional challenges. The cost of operating these systems has limited their use to high profile land and offshore use in most cases leaving a technology gap to be addressed in markets with cost constraints.

Although RSS technology has proven its value in the field, adoption in low-cost applications has been limited. High lost in hole(LIH) rates, day rates that are double or triple that of mud motors, and harsh drilling environments that can lead to premature failure of RSS electronics are all barriers to the use of RSS in many land markets. The horizontal land market requires a technology capable of providing the performance of an RSS with a cost structure that doesn't place it out of reach for operators and regions on a limited budget.

Today a fully-mechanical rotary steerable tool has been developed that provides full 3D directional control during full rotation of the drill string without the high costs of conventional RSS tools and without the sensitive and costly electronics. This rugged and durable push the bit design withstands the most challenging of formations, and reduces the number of vibration related failures. Without the limitations of conventional electronics, this tool can also handle high temperature environments while improving ROP (rate of penetration) verse conventional RSS. A proven 3-point geometry and strategically placed stabilization are utilized to reduce tortuosity and drill a premium wellbore at a cost well below that of standard RSS.

This paper provides case studies from North American land operations proving the ability of this fully mechanical RSS to drill at ROP's up to 50% higher than a steerable motor. Reduction in operating cost of as much as 40% vs RSS and minimized financial risk associated with lost in holes charges (LIH) over conventional RSS are shown in the supporting study.
A Novel Mechanistic Approach for Modeling Low Salinity Water Injection
Authors: Kazemi Nia Korrani Aboulghasem , Sepehrnoori Kamy , Delshad Mojdeh
Published: September 2013

Waterflooding as a secondary oil recovery method is still the most commonly used technique for fluid injection since 1865. Recently researchers have discovered that the injected water quality is important and it should be monitored in addition to volume of water injected. This technique is known as low salinity water injection, LoSal®1, Smart Waterflood and Advanced Ion Management.

Evidence from laboratory studies, supported by several field tests, has distinctly shown that injecting low salinity water can have a significant impact on oil recovery. Although there are many LoSal® experimental results reported in the literature, publications on modeling this process are scarce. In this paper, we propose a mechanistic modeling approach for the low salinity water injection. We believe no matter the manner and details of mechanism, it ought to be all about ions. The key objective in this approach is to link the water-rock chemistry to changes in the state of a rock (e.g., wettability). Since geochemical reactions are the basis for this mechanistic modeling, we would need a geochemical engine to handle geochemical reactions in the reservoir for properly modeling LoSal®. Toward this goal, it was decided to couple IPhreeqc, an open source geochemical module available by United States Geological Survey (USGS), with UTCHEM, an in-house research chemical flooding reservoir simulator developed at The University of Texas at Austin. An algorithm is presented for modeling the geochemistry in an IMPEC (implicit in pressure and explicit in concentration) solution algorithm. Finally, we show how apply the integrated tool, UTCHEM-IPhreeqc, to model low salinity water injection.

Geochemical-based models can easily be implemented in this modeling approach and also compared against experimental results for validation. Implementation of several mechanisms can finally reveal the dominant mechanism for the low salinity water injection.
Sodium Free Processing of Oil Sands Ores: Toward Total Water Management in Mining Operations
Authors: Mahmoudkhani Amir , Fenderson Thomas , Watson Philip , Nair Mohan , Wu Yongfu
Published: September 2013

Current water management strategies require recycling and reuse of oil sand process water (OSPW) as much as 80%. Continuous recycling and reuse of OSPW results in a degradation of the quality of water namely increases of total dissolved solids (TDS) and dissolved organic materials (DOM). This results in a net increase in operating and maintenance costs and an impact on extraction process and bitumen recovery. Remaining water containing fines and suspended clays adds to the mature fine tailings and associated problems for tailing ponds treatment and management. Presence of residual bitumen and other organics is known to create difficulties in common practices for flocculation and dewatering of tailings. With problems stated above, one may consider a pre-treatment approach in place of the common post-treatment remedies.

The ore grade profoundly affects the efficiency of bitumen recovery in the hot water extraction of bitumen which is a principal step in the current commercial technology for bitumen extraction in mining operations. Sodium hydroxide is often added to the conditioning step of the process and is needed to obtain higher bitumen recovery from most oil sand feeds. Use of NaOH, however, results in accumulation of sodium ions in recycled water, causing higher clay dispersion and producing tailings with poor geotechnical properties that turn into mature fine tailings. This is especially true for low grade and oxidized ores, which present the greatest challenges in bitumen recovery and produce the major portion of tailings. With current trends for increasing production from mining operations to almost double by 2020, industry has to adopt new technologies to manage tradeoffs between water and energy.

We present a new approach toward total water management by introducing novel process aids for sodium-free processing of various oil sands ores. Lab experimental data were analyzed to evaluate the efficiency on the processability of low grade oil sands, water chemistry and tailing management. Our results demonstrate that the use of new process aids during the conditioning process leads to an improvement in bitumen recovery from low grade oil sands and can accelerate tailings settling resulting in better water management. The process aids were also used in combination of polymer flocculants to treat process tailings, resulting in better tailings dewatering and consolidation. This approach offers a potential chemical solution for total water management that can be incorporated into current ore processing facilities and delivers some operational and economic benefits.