bluuebunny/crossref_metadata_2025 huggingface dataset:
Transferring Knowledge Through Decision Support: A Case Study in Drilling
Authors: Gundersen Odd Erik , Kucs Richard , Sheehy Tim , de Holden Mabel Susana
Published: June 2014

The new generation is primed to take on this challenge and lead the industry into the future. However, the industry will not simply pass the reigns to an unready resource, as experience is a critical component to success. Decision support systems can be an important source for sharing knowledge and experience, but they need to provide the right information at the right time.

We discuss how decision support software can and should both enhance the situation awareness of its users, as well as help transfer knowledge. Our view is based on Mica Endsley's model of situation awareness. We explain how oil well drilling monitoring can be understood according to this model, and we seek to define what exactly a situation related to the oil well drilling process is. Furthermore, we discuss knowledge transfer in relation to oil well drilling and the situation awareness model. Then, we show how the software we have developed performs in this regards both through an analysis and a use case that describes a commercial trial. Finally, the results of the commercial trial are discussed and some future work is considered.
Technology Application and Process Optimization for Success in Riserless Drilling
Authors: Groetsch Ryan , Mathur Rohit , Boyd Andrew , Williams Roger
Published: June 2014

Deepwater wells traditionally feature two or three riserless sections that present a unique set of issues. Any oversight in managing these issues could increase the risk to the wellbore and jeopardize the safe delivery of the entire project. Recent successes in an operator's field in the Gulf of Mexico indicated improvements could be made to a process that has been commonplace for the industry. In this case, many complications often encountered during riserless drilling were overcome by utilizing technologies that had been previously used in later sections of the wellbore.

These riserless sections have very soft, unconsolidated sediments, potential shallow water flow, torque-and-drag implications, positional uncertainty and close proximity potential to other wells in the field. This close proximity brings along another set of complications such as very large holes with concentric reamers, precise dogleg severity control, magnetic interference, and anti-collision issues. Any combination of these conditions may exist in a well.

Operators may want to consider adapting existing technology as a more cost-effective, efficient, and safe solution to riserless drilling complications. This paper presents case histories from successful deployments of available technologies to meet the demands of riserless drilling challenges. Technologies in focus are rotary steerable systems, gyro measurement while drilling (MWD), survey management and acoustic measurements in large hole sizes.

The oil and gas industry strives to manage risk, minimize non-productive time (NPT), increase efficiency, and reduce overall cost. The technologies and processes presented in this paper proved to be efficient in riserless drilling applications and helped the operator achieve overall project success. These technologies can be run separately or in conjunction, depending on the application.
Steering Efficiency and Directional Responsiveness - Definitions, Considerations, Drilling Systems Effects and Contributions to Performance Drilling Improvements
Authors: Mensa-Wilmot Graham , Gagneaux Jay , Langdon Sheldon , Benet Paul
Published: June 2014

Downhole drilling tools1,2, continue to see improvements in reliability, leading to extended mean times between failures (MTBF). Drive systems, specifically positive displacement motors (PDM), rotary steerable tools (RSS), and turbines have seen extensive improvements in MTBF. Consequently, technical successes on directional drilling programs, where such drive systems are commonly used have also improved. However, these gains do not always translate into meaningful operational success4, which is needed to drive down drilling costs. This situation is caused by some of the industry's perceptions and approach to drilling system design. Additionally, it is influenced by how projects are analyzed, and sometimes interpreted, with regards to performance drilling expectations.

This paper will discuss three types of success – technical, mechanical, and operational. It will also identify and discuss the reasons why gaps still exist between technical and operational success. In addition, evaluation processes developed to bridge the gap between technical and operational success will be discussed. Multiple case histories, highlighting the impact of the concepts and evaluation processes to be discussed in the paper, will be presented.
Automated MPD and an Engineered Solution: Case Histories from Western Canada
Authors: Medina Leiro , Baker Justin , Markabi Mazen , Rojas Jimmy , Tarique Zoro , Dow Blaine
Published: June 2014

Managed pressure drilling allows operators to address key technical risks such as narrow pore pressure and fracture gradient windows, influx management, sensitive wellbore stability environments and navigation of steep and unknown pore pressure ramps. In these applications, MPD may be the determining factor of delivering or not delivering the well.

Historically in North America land, operators have executed simplified forms of equipment-centric MPD in well-known basins. However, as unconventional development expands and new basins open up, subsurface pressure regimes present challenges that require a more intense engineered approach to MPD drilling, at least until the field is known. Applying engineering support alone does not guarantee success, though. MPD systems are designed to offer different degrees of pressure management precision and control. Depending on the complexity of the reservoir and geometry of the well design, an MPD solution appropriate for the application is also required.

The authors discuss the foundation of MPD automation using as an example, two systems with different degrees of automation control. Each was used for two distinct MPD projects in Western Canada. After determining the technical requirements of each basin, the appropriate MPD system was selected. In both instances, intensive drilling engineering design work was required to ensure the selected system was utilized successfully to drill these difficult wells. Each case unearthed unique lessons that allowed the drilling team to collectively evolve a step-change approach to MPD.
Multi-Machine Control Leads to Improved Rig Layout
Authors: Engum Erlend A , Haavind Erik , Enes Ståle , Holck Jesper
Published: June 2014

The 6th and 7th generation drilling rigs are increasingly using more automated and integrated control systems to reduce the number of operators needed on the drill floor, enhance safety, increase operational efficiency and predictability and reduce wear and tear on the equipment. A comprehensive multi machine, sensor and camera control system has been installed on several rigs currently in operations in the Gulf of Mexico. This system allows one to two operators to control and monitor all the tools in the tripping or stand building sequence with the ease of using one joystick.

This follow-up case study collects experiences of a rig using multi-machine control (MMC) by interviewing the rig crew, studying the drilling contractors KPIs and analysing logged data

Findings and lessons learnd have led to improved machine design and rig floor layout on the next generation drilling rigs. This paper also summarizes how the use of multi-machine controls and assembly line focused rig design together improves the effects automation has on staffing and efficiency of pipe logistics.
Degradable Fiber Pill for Lost Circulation in Fractured Reservoir Sections
Authors: Droger Nicolas , Eliseeva Ksenia , Todd Larry , Ellis Chelsea , Salih Omer , Silko Nikita , Fu Dan , Meyer Arnoud , Bermudez Raul
Published: June 2014

Lost circulation is one of the main causes of nonproductive time during drilling and impacts the success of cementing operations. Losses into the reservoir not only impact drilling, they potentially impact the reservoir, due to influx of quantities of drilling fluids that are potentially damaging, or will influence the production rate. Existing solutions are based mainly on particulates, which often are added to drilling fluids to plug fractures or to build up filtercake to cure fluid losses. When particulates are applied for curing losses in reservoir sections, it is desirable that the plugging materials maintain stability for sufficient time to allow well completion but eventually self-degrade to leave undamaged formation for future hydrocarbon production. The main challenges are the design of the lost-circulation material to cure losses into fractures of various widths and to provide plug stability and cleanup within a desired time frame over a broad bottomhole temperature range.

Fibers have shown good fracture-plugging behavior. Parameters affecting fiber performance include, but are not limited to, fluid viscosity, fiber concentration, fiber geometry, flow rate, effect of the wall, and fracture width. To effectively apply fibers as lost-circulation applications, a novel, fiber-laden fluid was designed for easy preparation on surface, allowing compatibility with bottomhole assemblies (BHAs). The decrease in velocity inside the fracture enables fibers to bridge and then plug the fracture, thus regaining circulation. The fibers are specially designed to degrade in an adjustable time frame sufficient to ensure plug stability until the well is completed. With time, the plug undergoes further degradation, leading to nondamaged formation for production.

This novel degradable solution has been successfully proven during field trials in various drilling scenarios ranging from severe to total losses with effective and efficient loss mitigation, without issues on placement through BHA and bit nozzles, and mitigating further reservoir damage.
Drilling with Induced Vibrations Improves ROP and Mitigates Stick/Slip in Vertical and Directional Wells
Authors: Clausen J. R. , Schen A. E. , Forster I. , Prill J. , Gee R.
Published: June 2014

For years drillers have been taught to mitigate all vibrations in the drillstring while drilling to maximize Rate of Penetration (ROP), limit bit damage, and extend bit life. While limiting lateral vibrations and stick/slip are proven ways to improve performance and maintain directional control, in recent years it has been conclusively proven in the field that inducing axial agitation with specialized downhole tools can significantly improve lateral reach. Currently, however, the benefits of downhole oscillation tools have not been thoroughly studied for other performance gains, such as improved ROP in non-directional wells.

An extensive research study, including lab and field testing, found that a low-frequency, benign axial vibration can increase the ROP significantly in all well types. Initial laboratory experiments were performed by inducing axial vibrations into the drilling process on a small scale drill bit in hard rock. Dramatic improvements in ROP and drilling efficiency were observed, with the added benefits of improved bit life and an unexpected reduction in stick/slip. This lab experiment was later tested in the field by utilizing a proven downhole oscillation tool in an active Bottom Hole Assembly (BHA) to create the effect that was simulated in the lab. The field tests showed the same results as the lab tests: significant performance gains were observed in several test wells using the downhole oscillation tool as compared to offset data. In addition, this same downhole oscillation tool showed drastically improved directional control when run above a Rotary Steerable System (RSS) tool, and stick/slip was practically eliminated with no negative effect on bit life or BHA reliability.

High-speed sensor data collected at the bit during both the lab and field tests will further demonstrate the validity of the theory. Testing for a hard-rock application with roller cone bits is forthcoming, as the data indicates possible performance gains in this environment as well.

Overall, the study revealed many benefits, such as improving well placement, reducing Non-Productive Time (NPT) and time to Total Depth (TD) by preventing BHA component damage through beneficial axial vibrations from the downhole oscillation tool. The data indicates that "benign vibration" can drastically improve drilling performance.
Nanosilicas as Accelerators in Oilwell Cementing at Low Temperatures
Authors: Pang Xueyu , Boul Peter J. , Jimenez Walmy Cuello
Published: June 2014

Accelerators are important cementing additives in deepwater wells where low temperatures can lengthen the wait-on-cement (WOC) time, potentially increasing the cost of operations. The cement set accelerators traditionally used for shortening WOC times are inorganic salts, such as CaCl2. These accelerators are known to have the potentially negative side effect of increasing the set cement permeability. Nanosilicas, on the other hand, can be advantageous compared to conventional cement set accelerators because they reduce the permeability while increasing the mechanical strength of cement-based materials. For this reason, nanosilicas are known to be particularly good candidates as replacement materials for traditional salt accelerators.

This study investigates the feasibility of using different sizes and aspect ratios of nanosilicas as cement hydration accelerators under low-temperature conditions 59°F (15°). The nanosilica activities are herein defined through their comparative advantages with traditional accelerators as well as through the advantages and disadvantages of the different nanosilicas resulting from their various sizes and shapes. While hydration of oilwell cement is known to be accelerated by the addition of nanosilica, the effects of nanosilica particle shape on cement hydration kinetics has not been previously investigated. The isothermal calorimetry experiments conducted in this study reveal that just as smaller nanosilica particle sizes increase the cement set acceleration so do higher nanosilica aspect ratios.

The effects of slurry density on the relative merits of CaCl2 and nanosilica are also investigated. In regular-weight slurries, the effectiveness of nanosilica acceleration appears to be weaker than that of CaCl2, especially during early ages (≤ 3 days). In lightweight slurries, the effectiveness of nanosilica acceleration can be much stronger than that of CaCl2, especially when mid- to long-term properties (≥ 2 days) are considered. Smaller particle sizes and higher aspect ratios enhance the acceleration effect of nanosilica. The compressive strength development of lightweight oilwell cements with and without accelerators was also investigated. Lightweight cements accelerated with nanosilica displayed 7-day compressive strengths up to 136% higher than those accelerated with CaCl2.
Engineered Oilwell-cement-based Systems for Optimum Validation of Cased-hole Ultrasonic Tools
Authors: Jimenez Walmy Cuello , Pang Xueyu , Gilstrap Tatiana
Published: June 2014

Cement is a critical component in an oil well because it provides sealing and zonal isolation within the well. To help ensure proper performance of a cementing operation, various evaluation techniques/tools have been developed and used over the years, including some based on ultrasonic pulse echo technology. Ultrasonic pulse echo evaluation tools can play a key role in determining in-situ cement performance and if any remedial cementing is required. As the oil and gas industry continues to migrate toward more challenging reservoirs with increasingly harsh conditions, and coupled with more stringent regulatory requirements, significant technology improvements are helping ensure well integrity and safety. For example, ultrasonic tools are being reengineered for the capability to penetrate thick-walled casings (>0.75 in.) commonly used in complex situations, such as deepwater and high-pressure/high-temperature (HP/HT) wells. Meanwhile, there is also great demand for better optimized validation techniques to confirm the operational performance of these new evaluation tools. This paper focuses on investigating the use of oilwell cements as validation media of current and advanced ultrasonic tools designed for cement and casing evaluations.

The evaluation system developed in this study consists of a combination of various validation media with a wide range of acoustic impedances (1.5 to 8.5 MRayl) and a multicasing fixture with casing wall thicknesses ranging from 0.4 to 1.4 in. This system could be used for the evaluation of tool performance in the presence of various muds and across a range of temperature and pressure conditions. Performance effectiveness was evaluated by measuring the acoustic impedance of the different media bonded to a multithickness casing and comparing the results to those acquired by direct acoustic measurement performed on the same media. The evolution of acoustic properties over time, directly related to cement hydration, was also monitored.

An advanced pulse echo technology tool was used to perform preliminary validation using the newly developed evaluation system. This resulted in a clear trend of impedance evolution that correlates well with the direct impedance measurement of cement media.
Incorporating Completion and Drilling Techniques to Enhance and Maximize Production Over the Life of the Well
Authors: Smith Lee , Scott Greg
Published: June 2014

This paper describes application of an integrated approach that combines drilling and completion techniques in a new use of reaming tools currently used for reaming-while-drilling (RWD) operations, in a way that minimizes the need for SOP of using a dedicated reamer run. The RWD application provides the enhanced wellbore geometry needed to design and engineer solutions using maximum size (OD) conventional casing, liners, expandable casing and multiple swellable packers. This type of assembly for drilling /completion design, currently utilized in multiple Williston Basin wells, ND, is shown to consistently result in shorter drilling time and successful first casing/liner runs. Currently this type of cross functional approach has been used on over 400 wells/ 4,000,000 ft. of lateral.
Wellbore Strengthening and Casing Smear: The Common Underlying Mechanism
Authors: van Oort Eric , Razavi Seyed Omid
Published: June 2014

A variety of Wellbore Strengthening (WBS) methods have been introduced and successfully applied in field drilling practice over the last decade, with origins going back to the late 1980's when the DEA13 investigation was carried out. In addition, a beneficial casing "smear" effect has been observed in recent years during drilling-with-casing or casing-while-drilling (CWD) operations, preventing lost circulation even when drilling highly depleted formations at high annular circulating pressures. Casing smear mimics WBS effects observed during regular drilling operations in its ability to effectively extend fracture gradients and prevent lost circulation, which is of great benefit to drilling difficult wells with tight drilling margins such as (ultra-)deepwater wells. In fact, when used appropriately, WBS and casing smear may offer well construction benefits that are on par with those of managed pressure drilling (MPD) and dual gradient drilling (DGD), at reduced equipment usage, complexity and cost.

To explain WBS and casing smear phenomena, a variety of different mechanisms have been proposed. These broadly fall into three categories: (1) Wellbore Stress Augmentation (WSA) - augmenting the hoop stress or closure stress around the wellbore by propping open induced fractures either at the wellbore face or somewhere into the fracture; (2) Fracture Propagation Resistance (FPR) - effective solids plugging of any fracture tip, thereby interfering with effective fracture growth; (3) Wellbore Face Sealing (WFS) - forming a uniform seal around the wellbore that prevents fluid leak-off and interferes with fracturing. Here, we offer a re-examination of previously published data (such as open-hole leak-off tests) and theoretical results, and present our own independent results and assessments to show that WBS and casing smear have a common, unified origin. It will be shown that the only mechanism that consistently explains all the data obtained to date is, in fact, the FPR mechanism. Moreover, guidelines are presented to exploit FPR optimally for the benefit of complex well construction.
First Field-Testing Of A New Rotary Steerable Drilling Liner Technology On Alaska North Slope
Authors: Hobbs Greg , Stinson Rob , Alvord Chip , Anyanwu Okechukwu N. , Klotz Christian , Mohammad Muntasar
Published: June 2014

Conventional drilling through lower intermediate intervals in the southern portion of the Alpine field on Alaska's North Slope (ANS) has posed significant challenges, resulting in longer than planned well delivery timing, and additional costs due to accumulated drilling complications. While unstable shale sections can be drilled without significant issues, hole collapse has caused difficulties while tripping out of hole and running casings. The need to overcome these challenges for long term economical access to develop the Alpine sands reservoir section beneath the shale layers led to numerous project initiatives and operational changes. These actions all produced incremental advances to mitigate wellbore stability issues, but never provided a guarantee that a liner would be successfully run to total depth of the open hole section after the trips required to complete this task conventionally.

In 2011, a new Steerable Drilling Liner system was proposed as a possible solution for drilling these wellbores while sealing off the troublesome shales. An extensive feasibility study was conducted to ascertain the technical possibility of deploying this technology safely within the Alpine field. Candidate wells were identified and a phased implementation approach was adopted to conduct field trials in order of increasing complexity of well trajectory and open hole and liner section lengths. This paper provides insights into the new technology and the field trial program. We cover the lessons learned and further improvement opportunities applicable to future deployments in this area. Based on the success of the Steerable Drilling Liner technology in this application, further deployments are scheduled to take advantage of developing Alpine reservoir sands in an economical and safe manner.
Macondo Litigation Update - How Court Decisions Will Impact Oilfield Contracting and Insurance Practices
Authors: Moomjian Cary A.
Published: June 2014

Decisions in the Macondo litigation pending in a U.S. District Court in New Orleans will impact operators, drillers, service and supply companies as well as insurance underwriters.

Phases I and II of the Macondo trial have been concluded. Phase III is expected to commence in the first half of 2014. The paper primarily reviews pre-trial, trial and appellate court proceedings relating to the contractual indemnification, release and insurance provisions of the applicable drilling and cementing contracts that BP entered into with Transocean and Halliburton, respectively. The paper includes commentary from the author based on over 35 years of experience as a drilling company legal, contractual and risk management executive.

Initial pre-trial Macondo Court rulings addressed whether contractual indemnification or releases may apply even in the event of gross negligence, strict statutory liability or willful misconduct. These rulings also determined whether indemnification may include punitive damages or apply to penalties assessed under the Oil Pollution Act of 1990 ("OPA'90"), the Clean Water Act ("CWA") or the Outer Continental Shelf Lands Act ("OCSLA"). In future proceedings, the Court is expected to determine if a material breach of contract will invalidate traditional oilfield indemnity and release provisions.

Trial and appellate court rulings in Macondo-related litigation have considered the nature and scope of insurance coverage accorded to BP as an additional insured party under Transocean's liability insurance policies. These rulings focus on both the drilling contract provisions naming BP as an additional assured and the terms of the associated insurance agreements. Although this litigation is currently under a second appellate review, the important implications of these proceedings on oilfield contracts and insurance agreements are discussed in the paper.

There can be no doubt that the Macondo litigation will have a profound impact on the way oilfield activities are conducted, contracted and insured. The paper is intended to assist those involved in contracts and risk management in understanding the judicial proceedings and determining how they may impact oilfield contracts and insurance agreements.
Expanding the Extended Reach Envelope at Chayvo Field, Sakhalin Island
Authors: Gupta Vishwas P. , Yeap Angel H. , Fischer Kyle M. , Mathis Randall S. , Egan Michael J.
Published: June 2014

The second drilling campaign at the Chayvo field, located offshore Sakhalin Island, targeted the development of a new reservoir zone using extended reach wells from onshore. A total of 4 oil producers and 1 gas injector were planned to develop the northern portion of the reservoir. To effectively drain the east and west flanks of this reservoir, record length wells beyond the current extended reach drilling (ERD) envelope were required. Key challenges included high torque and drag, wellbore positioning in a thin oil column, wellbore stability, long horizontal completions, and downhole tool telemetry. This paper describes the Operator's experience with drilling these challenging wells that resulted in several new ERD records. Key well design features, equipment upgrades, and lessons learned will be discussed.

ERD is an established technique to economically access reserves from existing infrastructure, reducing the need for additional drill centers and consequently reducing the drilling and facilities environmental footprint. Continuing advancement of the ERD envelope along with delivering cost-effective wells will further maximize the benefits of this technique. The case history described in this paper illustrates that the advancement of the ERD envelope is possible through detailed planning, technical design, and operational excellence.

The planning of these wells built upon the Operator's previous ERD experience along with additional tools and techniques. Three of the project wells set new worldwide ERD records for measured depth; the longest well, Z-42, established new records for measured depth (12,700m) and horizontal reach (11,739m). Completion designs were optimized to successfully run a ∼3,600m long open hole completion, and the well was finished in ∼70 days. As a result of this successful development, additional wells are being planned in conjunction with technology advancement initiatives that will push the ERD measured depth envelope to 13km and longer.
Experimental Assessment of Casing Expansion as a Solution to Microannular Gas Migration
Authors: Kupresan Darko , Heathman James , Radonjic Mileva
Published: June 2014

The objective of this research was to investigate the potential impact of expandable casing technology on the remediation of Sustained Casing Pressure (SCP). Varying magnitudes of SCP exist in the Gulf of Mexico (GOM), where over 80% of casing strings exhibiting SCP are production and surface casings, representing a great technical, economic, and environmental risk. Situations in which SCP is observed usually result in costly and frequently unsuccessful remediation efforts.

The technique proposed in this project with expandable casing can be done during drilling, producing, or during the abandonment process. A unique bench-scale physical model was used to simulate expansion of a previously-cemented casing under field-like conditions. Experimental measurements obtained during low-percentage casing expansion exhibited improvement of cement integrity with significant changes in the cement sheath. Successful multi-rate flow-through experiments with nitrogen gas showed the effectiveness of this technique in complete closure of microannular gas leakage pathways, providing ideal cement remediation. If implemented, this technology has potential to become a cement remediation technique for leaks behind the casing.
A Field-Based Method of Calibrating Inclinometers for Floating Drilling and Completion Operations with Applications of the Method to Reduce Differential Flex Joint Angles
Authors: Mouton David E. , Newberry David R.
Published: June 2014

Inclinometers in deepwater drilling and completion operations provide essential information These devices are either manual ("bullseyes") or Electronic Riser Angle (ERA) systems that report angles of subsea equipment such as BOP's, flex joints, and wellheads. These readings, particularly from the manual devices, can be inaccurate if not properly calibrated or "zeroed" on floating vessels. As a result, important operational decisions may be based on erroneous inclinometer readings. Incorrect decisions based on such readings could lead to a unnecessary stop in operations or a continuance of operations that may cause damage to subsea pressure containment equipment, with a resultant potential risk to the operability of this critical safety system.
Could Emulsified Friction Reducers Prevent Robust Friction Reduction?
Authors: Tucker Kristen M. , McElfresh Paul M.
Published: June 2014

Many of the friction reducers in use today demonstrate various degrees of performance based on the type of mixing water utilized, especially those products which are designed as an "emulsion" (Aften et al. 2009; Zelenev et al. 2009). In addition to molecular differences between various polyacrylamides, the nature of the oil external qualities of an emulsion can pose challenges to breaking (or inverting) the emulsions (Aften et al. 2009; Zelenev et al. 2009). These factors directly affect hydration rates and are dependent on water quality factors like salinity, dissolved materials, suspended materials, and pH (Aften et al. 2009; Zelenev et al. 2009).

Therefore, it is postulated that if the friction reducers are applied in another form such as a powder or slurried powder, they could have an inherent broader spectrum of applicability and efficiency. The purpose of this study is to determine the differences in performance of several friction reducers in various water qualities in order to determine if the type of polymer application enhances or restricts the range of applicability. Multiple polyacrylamides are tested in different forms including oil external emulsions, powder, and slurried powder. These friction reducers are tested on a flow loop in up to four different water qualities including fresh water, 5% KCl, sea water, and produced water.

The results of this testing show that some oil external emulsions are limited to smaller ranges of applicable water qualities. The powder polyacrylamide sample has a broad range of applicability, while the slurried powder shows comparable and often superior performance, especially in poor water quality.

Switching to a slurried powder friction reducer would enhance operational simplicity and economies of scale by eliminating the need for several products. The percent polymer activity would also surpass that of emulsions which could ultimately reduce the total volume pumped and, in turn, cost, emissions, time, and truck traffic due to freight.
One Tcf From One Well: The Design of a 500 MMscf/D Subsea Well for Offshore Mega Gas Fields
Authors: Reeves Donald F. , Healy John C.
Published: June 2014

With the continued discovery of large gas fields worldwide that have highly prolific sandstone reservoirs, the ability to design wells capable of recovering ultra-high volumes of gas will become of great interest. The project teams for these fields will be challenged to develop the fields with the smallest well count possible. The results from this study could prove useful to production and completion teams supporting large gas field developments. This paper presents a study to determine the feasibility of a subsea sand control gas well producing at rates up to 500 MMscf/D and recovering one trillion cubic feet (Tcf) of gas. Because the size of recent gas field discoveries is so large, reservoir simulation models will show that recoveries exceeding one Tcf are possible from a single location. Considering the huge cost to install deep water subsea sand controlled wells, reducing the total well count necessary to deplete the field is a business imperative. The results of the study show that completing a sand control well that can produce 500 MMscf/D and recover one Tcf is plausible. The details of the well productivity, completion design concepts and relevant comparison of analogue fields is shown. In conclusion, production and completion engineers involved in development of mega gas fields should at least consider planning for such wells.
Chemical Qualification and Field Application of a Nondamaging Scale Squeeze Treatment in the Mangala Field
Authors: Chavan Chetan , Rao Eshwar , Jha Mihir , Tiwari Shobhit , Graham Gordon , Stalker Robert
Published: June 2014

Significant production rate decline and a few ESP failures were observed in the Mangala field, onshore India, due to scaling. Scale inhibitor squeeze treatments were required to arrest the production decline and prevent additional ESP failures. The Mangala crude oil is extremely waxy, with a wax appearance temperature (WAT) of 62°C and a reservoir temperature of 65°C. This meant that prior to chemical application, fluids would have to be pre-heated to prevent wax formation and potential damage to the near wellbore area. The produced water chemistry included iron concentrations in the region of 5 - 15 mg/l, which was related to the presence of significant quantity of siderite within the formation and which could have resulted in potential formation damage due to iron dissolution when applying pre-selected acid-phosphonate inhibitors. Additionally, the two main producing formations FM3 and FM 4 are produced from long horizontal wells completed with stand-alone screens. Chemical placement in the wells therefore proved to be a significant challenge, and treatments were designed to achieve placement across the water producing zones.

This paper describes the squeeze chemical selection for minimisation of formation damage risks associated with treatments in this particularly challenging case study, with WAT close to reservoir temperature and the presence of reactive iron minerals. The impact that these factors had on both chemical performance and on the potential applicability of the selected chemicals is discussed. The paper also discusses pre-conditioning treatments pumped in these wells to regain productivity. The work also demonstrates how a combination of laboratory testing and treatment modelling has been used to minimise the potential for formation damage while at the same time maximising chemical treatment of the water producing zones. The detailed mineralogy and heterogeneity of the reservoir formations, the impact of production conditions and elevated iron on the performance of the selected chemicals are all described as well as the selection of alternative generic chemicals which were not poisoned by the increased iron. Initial field treatments have been conducted and preliminary results will also be presented which concur with the chemical qualification and treatment design
A Novel Slow-Release Rheology Modifier for Well Treatment Fluids
Authors: Li Leiming , Zhou Jia , Sun Hong , Qu Qi
Published: June 2014

Fluids with high viscosity are needed during hydraulic fracturing to convey the high pressure to create fractures in the rock formation, and to carry the proppant downhole to hold these fractures open after the treatment. A number of oxidative breakers, live and/or encapsulated, are usually mixed into the fluids upon pumping downhole to break the fluids after the treatment to flow back fluids and minimize the damage to the formation. It is not always easy to control the breaking rate of these breakers. If they break the fluids too early in the treatment, the fracturing fluids may not effectively create fractures, and screenout may occur. Well treatment fluids for other oilfield applications may also require controllable slow-release rheology modifiers.

A novel rheology modifier has been identified recently and successfully used in a number of well treatment fluid systems. In one example, the rheology modifier can be used to break crosslinked fracturing fluids at desired rates. By adding the rheology modifier into the fracturing fluids prepared with the crosslinked polysaccharides, the fully controllable breaking of the fluids has been realized in our laboratory tests. In another example, the rheology modifier can be used to create a temporary plug that gradually self-breaks at a controllable rate. Low-residue and salt-tolerant hydroxyethyl cellulose (HEC) solution can be crosslinked into a viscous gel and used as a temporary gel plug. By including the rheology modifier at selected concentrations in the gel, the originally thick temporary plug can be gradually thinned to flowable fluid after the preset period of time. This way, the temporary plug can be easily removed from the wellbore after it has served its purpose. The performance of the rheology modifier in the selected well treatment fluid systems will be discussed.
Acid or Propped Fracturing in Deep Carbonates? Experiments and Field Results
Authors: Oliveira T. J. , Neumann L. F. , Azevedo C. T
Published: June 2014

The deep and hard carbonates found offshore Brazil are being extensively evaluated, and some of them would require fracture stimulation to enable commercial development. Due to the high effective normal stresses expected during the exploitation stage of pre-salt development, acid fractures could have very low conductivity values, depending on formation mechanical properties. Since perform propped fractures is more risky, it is important to create selection criteria to know precisely the fracture technique to be used. There is no agreement in the technical community regarding the survival of an acid fracture at closure stress greater than 5,000 psi. However, the experience that leads to this controversy is mainly based on: (1) wells on land and, (2) few published tests on rocks with mechanical properties compatible with those depths.

This article aims to discuss Petrobras’ fracturing selection criteria development. The experimental data currently available for acid fracturing Brazilian deep carbonates will be presented. Laboratory test are performed to verify whether an acid induced fracture can withstand high effective normal stresses, keeping an acceptable conductivity. Key mechanical properties are measured in order to understand acid fracture conductivity behavior under stress. These mechanical properties are correlated with log data to allow the use of laboratory results on the fracture technique decision of a particular well. Field data regarding acid fractures wells will also be addressed.
GaStim Concept - A Novel Technique for Well Stimulation. Part II: From Laboratory to Field Pilot Testing
Authors: Restrepo Alejandro , Ocampo Alonso , Lopera Sergio , Coronado Jorge L. , Sanabria Rosa B. , Alzate Luis G. , Hernandez Sergio
Published: June 2014

The present work is the continuation of SPE 152309 "GaStim Concept - A Novel Technique for Well Stimulation. Part I: Understanding the Physics" and contains further experimental work and field pilot testing stages of the GaStimulation method already proposed by the authors. Systems studied correspond to quartz-arenites containing volatile oil and retrograde gas condensates exhibiting hydrocarbon permeability impairment under depletion. In such systems, treatment penetration and adsorption are key factors for benefit sustainment. Supported by the theoretical background and preliminary lab tests presented in part I, the second stage of the GaStim project was planned and executed covering the testing of additional chemistries, pilot well candidate selection and execution and results evaluation. Three field pilots are reported; A first one of induced water removal after frac by stand-alone gas injection; the second, where gas + chemical dispersion is injected to reach a condensate damage radius beyond 200 ft and a third one, corresponding to a volatile oil system in which asphaltene damage have been partially re-established at reservoir level by gas / solvent co-injection. In the first scenario, Sw reduction / Kg improvement is attained in the gastimulated area probably by coupled effects of evaporation and water slug displacement. For the condensate blockage scenario, it was noted that micellar type of surfactants exhibit the best performance when tested against IFT reduction capacity, Kg re-establishment and liquid bank re-mobilization. In this case, it was also observed that the tuning of chemical concentrations and deployment method are key to maximize hydrocarbon flow capacity and minimize surface back flow emulsion after Gastimulation. Finally and for the third scenario, it is noted that oil declination trend is positively changed after solvent + gas co-injection from a gas injector well. Further experimental work is planned to support modelling approaches both aimed on improving design criteria and expanding the potential of the technique into more challenging environments.
Experimental Study on the Cement-Formation Bonding
Authors: Opedal Nils , Todorovic Jelena , Torsæter Malin , Vrålstad Torbjørn , Mushtaq Waqas
Published: June 2014

Detailed information on the quality of the cement job is vital to ensure economical, safe and stable production from a reservoir. A crucial part of this is the ability of cement to bond to the formation. Improper removal of drilling fluid or cement placement, or debonding due to unfavorable wellbore conditions can create potential flowpaths. Loss of zonal isolation from cement sheath failure can appear at three possible locations: at the cement-formation interface, in the bulk cement or at the casing-cement interface.

This experimental study focused on the cement-formation interface. The primary objective was to quantify the effect of various rock formation types on the cement-formation bonding, and the effect of altering the rock surface with various drilling fluid films before cementing. The secondary objective was to visualize the interfaces using micro-computed X-ray tomography (p-CT) and to observe any link between the measured shear bond strength and the presence of pores, cavities or films along the cement-formation interface.

The results showed that the different rock formations exhibited different interactions with the cement. However, it was also shown that the presence of drilling fluid, and drilling fluid type, were more crucial parameters for cement-formation bonding. The drilling fluid presence reduced the bonding strength, and it was shown that by using oil- or water-based drilling fluids the cement-formation bond was affected differently.
The Time-Dependent Permeability Damage Caused by Fracture Fluid
Authors: Bostrom N. , Chertov M. , Pagels M. , Willberg D. , Chertova A. , Davis M. , Zagorski W.
Published: June 2014

Hydraulic fracturing causes a large amount of fluid to leak off into unconventional reservoirs and the fluid is not recovered through flowback. The fluids enter the pore structure of the formation, and the presence of the invading phase blocks the in-situ phase. This event reduces permeability, particularly in unconventional reservoirs. Operators shut-in the well for an arbitrary amount of time after fracturing. The time could allow the phase blocks to dissipate, increasing permeability. Conventional core flow tests and relative permeability evaluations using centrifuge drainage tests are unreliable—if not impossible—in these ultralow-permeability unconventional rocks.

We present a method to measure the gas permeability on core plugs of mudstones at reservoir conditions, both before and periodically after the plug was exposed to fracture fluid. The change in gas permeability over time allows optimization of the shut-in time. In addition, the combined rate of leakoff and imbibition is measured while the material is exposed to fluid. At the conclusion of the test, the axial water profile is determined by measuring unconfined compressive strength using the mechanical scratch machine and water saturation with Karl Fisher titration.

Initially, the samples are saturated with gas and have the highest permeability. As the plug is then exposed to water, water imbibes into the core forming a water block. The water is removed from the face of the plug. Immediately after the core was exposed to water, the permeability drops below the detection limit. In most core tested, the water block dissipates over time increasing the permeability. Experimental results on core plugs from two major shale plays show that imbibition and fluid loss into ultralow-permeability rock can be substantial, but these processes are also highly variable. We developed a measure of the phase block dissipation. The information gives operators a quantitative measure to determine the length of shut-in periods and for the development of other methods to minimize the damage from water imbibition.
Advancing Chemical Sand and Fines Control Using Zeta Potential Altering Chemistry by Using Advanced Fluid Placement Techniques
Authors: Singh Pratyush , Ludanova Nataliya , van Petegem Ron
Published: June 2014

Sand and fines production is one of the oldest problems in the petroleum industry and one of the toughest to solve. Today, many sand control technologies and methods exist and in certain cases some sand and fines production is manageable, while for others it cannot be tolerated at all. Also, many wells do not produce sand or fines from the onset and may not require a sand control solution until later in their lives. Chemical sand control solutions have been around for many years and have always been attractive due to their ability to be installed without any restrictions to the well bore geometry. However due to the difficulties with placement, and in many cases their association with some degree of reduction in permeability, there have been reservations regarding the use of chemical methods as a standard. This paper presents a unique chemistry that increases the maximum sand/fines free rate without a significant reduction in permeability and discusses the advanced placement techniques essential for a successful application. It includes study of two hundred and fifty wells which have been treated with zeta potential altering chemistry and presents analysis of both failed and successful applications and the lessons learned.