bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Before Closure Analysis Model for Unconventional Reservoirs
Authors: Lamei H.. , Soliman M. Y. 
Published: June 2014

Abstract
Minifrac/diagnostic fracture injection tests (DFITs) are an important and integral part of hydraulic fracture design and reservoir evaluation. Models for analysis of the before and after closure data have been developed. While several models exist and are being used to analyze the after closure data, before closure analysis (BCA) is not widely used, and only a handful of models have been developed. Additionally, the models are based on similar approaches and assumptions. This paper introduces a new BCA model based on rigorous treatment of the fluid flow equations in the fracture and the formation. In this new model, the assumptions of linear leakoff and short injection time for a minifrac test are made. In general, these assumptions are valid. In unconventional reservoirs, where permeability is expected to be very low, the assumption of linear leakoff is particularly valid and would last most of the duration of the before closure period. In most minifrac tests, the injection time is relatively small with respect to after shut-in time, which validates this new model assumption of short injection time. Fracture stiffness is a critical parameter when using this model, which can be easily calculated or measured from logging or experimental data. By using the before closure model presented here, formation permeability could be estimated by interpretation of the slope of straight line in the specialized Cartesian plot using before closure data.
This paper details the development of the new model and compares it to existing models. In addition, several field examples from unconventional formations are presented and analyzed using various techniques, demonstrating the applicability of this new model. The results are also compared to the after closure analysis (ACA).
An Optimal Approach to Shale Gas and Oil Exploration Beyond North America
Authors: Madhoo Hamechan A. , Acevedo Andres , Koley Manas , Bryant Ian , Laver Rod 
Published: June 2014

Abstract
Exploitation of shale plays is viewed by many as a major resource for future economies of many countries. To date, most exploitation of this resource has centered on North America where the existing high onshore well count previously drilled for conventional resources guides pursuit of unconventional plays.
The situation is, for example, very different across onshore Europe, which has a low existing well count for conventional resources and notable socio-political and infrastructure challenges, such as high-population densities. To be successful, the delineation of European shale plays must use existing data for exploration and drill a reduced number of wells during exploration.
During the exploration phase, the ability to manage uncertainty and make informed decisions across the potential shale plays is vital. An optimal approach is proposed, whereby all possible surface and subsurface sources of data are integrated and exploration screening is done based on advanced petroleum systems modeling. To illustrate the approach, data from onshore Netherlands has been selected. The West Netherlands Basin and Roer Valley Graben contain organic-rich Jurassic sequences within the Altena Group, including the well-known Posidonia Shale Formation. This formation is currently being targeted as a potential unconventional resource.
A fully integrated 3D geological model – including an advanced 3D petroleum systems model – is presented, which includes critical spatial information, such as geographical terrains and surface constraints. Results from this approach clearly demonstrate areas of higher prospectivity, and, importantly, their associated uncertainty. This allows E&P companies to select areas that have the best chance of success.
Influence Factors of Fracability in Nonmarine Shale
Authors: Fang Changliang , Amro Mohammed 
Published: June 2014

Abstract
Fracability, the capability of shale that can be fractured effectively, is the most critical evaluation parameters in shale gas production. At present, it is generally recognized that using mineral composition and rock mechanics parameters to represent shale fracability is difficult to fully reflect the comprehensive properties of shale in hydraulic fracturing. However, so far all fracturing research about shale gas is almost considering marine shale and the understanding of shale fracability is confined and trapped within marine shale. Since shallow deposit of sedimentary strata in China is non-marine (lacustrine) facies sediments, China pay increasing attention to non-marine shale, which is opposite to the situation in Europe, and with the deepening of shale gas exploration, Europe will focus more on the non-marine shale in following decades. Due to the fact that lacustrine shale deposits differ from marine deposits in sedimentary environment, the former are always with frequent sand and mud interbed, interlayers development. Therefore, the influence factors of fracability in non-marine shale seemed more complexes and the research of shale fracability becomes more significant.
After general contrastive study of sedimentary environment, gas generation, mineralogy and physical properties of non-marine and marine shale based on literature data, this paper separately analysed the fracability influence factors (including sedimentary environment, mineral composition, diagenesis, brittleness, nature fracture, etc.) of non-marine shale focused on the Mesozoic Triassic Yanchang Formation shale in Ordos Basin of China. Moreover, comprehensive consideration of all above influence factors and statement of some fracability evaluation methods have been implemented. Unified and quantitative evaluation of fracability influence factors in non-marine and marine shale has been discussed afterwards. The summary of main influence factors of fracability in non-marine shale not only improved the shale fracability research, but also could guide the hydraulic fracturing practice.
Integrated BHA System Drills Curve/Lateral in One Run at Record ROP Saving Seven Days Rig Time
Authors: Meli Ricardo , Salas Carlos , Martin Rodrigo , Roa Edwin Restrepo , Nervi Virginia , Zaheer Aamer , Durairajan Bala , Hill Richard 
Published: June 2014

Abstract Rodrigo Martin
Apache Energia Argentina recently commenced horizontal drilling activity to develop shale gas reserves in Neuquén basin, Argentina. On the first well, the curve was drilled with a 12¼-in PDC bit on a positive displacement motor (PDM) bottom hole assembly. The lateral was drilled with an 8½" PDC on a point-the-bit rotary steerable system. A motor BHA was used in the curve because a standard RSS could not deliver the required dogleg severity (DLS). To optimize operations, the operator wanted to complete the curve and lateral with a single 8½" PDC bit. However, the lack of a high-build rate RSS tool required the curve to be drilled with a motor building to 50° of inclination then tripping for a point-the-bit RSS to TD the lateral. The single diameter strategy was successfully executed but further NPT reduction was still possible.
The challenge was to drill the curve and lateral with a high build-rate RSS and a single 8½" PDC in one run to eliminate a trip to change the directional drilling system. The introduction of an inclination hold and azimuth software system would enable the hybrid RSS tool, created to build the aggressive curve angle, to continue efficiently drilling in the lateral saving an additional trip. An engineering analysis was then launched to design an application specific PDC bit for the hybrid RSS. An FEA-based system was employed to analyze offset BHAs, directional profiles, bit technologies and mud properties. The study revealed that the baseline PDC was delivering excellent ROP in both the curve and lateral sections, but t modifications would be required to improve the bit's dynamic stability. A modified 8½-in SDi513bit was proposed that featured a customized cutting structure and gauge for improved stability.
Next, a rock strength analysis system was used to determine characteristics of lithologies encountered in the field. The study determined that Quintuco (curve) and Vaca Muerta (lateral) formations have relatively low unconfined compressive strengths (3-15 kpsi) but vibration potential in Quintuco formation is moderate. Computer simulations were run to map lateral/axial acceleration and bit torque on the hybrid RSS. The results showed that the new PDC design displayed a significant increase in dynamic stability compared to the baseline bit with similar high rate of penetration (ROP) potential.
The shale optimized BHA was run and it drilled 1289m of curve and lateral in one run at a record ROP of 9.64 m/hr, 35% faster than the offset average. The high build-rate hybrid RSS landed the wellbore at 96° inclination with a maximum turning radius of 11.8°/30m increasing reservoir exposure within the allotted acreage unit. The increased ROP enabled Apache to reach total depth (TD) seven days ahead of plan with savings of $595,000USD.
Intermixing of Cementing Fluids: Understanding Mud Displacement and Cement Placement
Authors: Chen Zhongming , Chaudhary Saleem , Shine Joe 
Published: June 2014

Abstract
Mud removal and cement placement during a cementing operation are key factors to ensuring zonal isolation. Actual well testing results show that majority of wells have zonal communication during the life of production. The communication between water and oil zones may significantly affect oil production and require expensive remedial squeeze treatments. Fully understanding the flow characteristics and interactive behaviors in mud, spacer, and cement is an important step to ensure critical zonal isolation.
A newly developed computational fluid dynamics model helps end users better understand the transport phenomena of intermixing multiple fluids. Fluid decay resulting from the intermixing involving the mud, spacer, and cement systems is quantified for given downhole conditions of wellbore geometry, fluid properties, pump rates and casing centralization. The robust method allows the analysis of potential hydrocarbon production zonal isolation success and optimization of cement placement. This advanced fluid displacement simulator has been field verified with impressive results for a wide range of annuli. A recently developed pseudo 3-D visualization module aids in understanding the complex phenomena as well.
Some field cases used for verification are included. The detailed job analysis demonstrates the methodology used to study the effects of fluid systems, pump rates, and centralization configurations and provides application engineers the opportunity to understand different scenarios while optimizing key parameters to achieve top tier results.
Evaluating Cost Efficiency of Rigless P&A for Subsea Multiwell Campaign
Authors: Moeinikia Fatemeh , Fjelde Kjell Kåre , Saasen Arild , Vrålstad Torbjørn , Arild Øystein 
Published: June 2014

Abstract
In a few years there will be a need for performing a considerable number of subsea plug and abandonment (P&A) on the Norwegian Continental Shelf (NCS). There are certain challenges associated with that such as more difficult access to subsea wells compared to ordinary platform wells, high daily rates of semi-submersible rigs and the fact that these rigs will be allocated for drilling new exploration and production wells to sustain the hydrocarbon production. For the moment there is large focus on looking for rigless technologies to decrease P&A cost and use of rig time. A probabilistic approach should be used to assess the cost and duration saving potential of such technologies relative to semi-submersible rigs.
In this paper, we will consider rigless technologies for performing parts of the P&A operation. For the first time, a risk based probabilistic approach including learning curves, correlations and possible risk events is used to evaluate subsea batch operated P&A.
A realistic example case which includes the use of a semi-submersible rig for batch operated P&A of subsea production wells is used to show how a probabilistic methodology can be implemented for obtaining probabilistic estimates of P&A cost and duration. Inclusion of learning curves and correlations makes the application of a probabilistic approach for multi-well campaigns challenging. It is demonstrated how to incorporate learning curves, correlations and possible risk events to capture a realistic range of cost and duration for multi-well P&A. In a second operational example, a light well intervention vessel is employed to accomplish preparatory work as well as wellhead cutting and removal for P&A of the subsea production wells in batch campaigns. These two case studies will be compared from a cost and duration point of view and it is shown that there are significant cost and duration savings related to transferring P&A activities from rigs to alternative intervention and vessel technologies.
HP/HT Exploration Well in Offshore Malaysia Pushed Automated MPD System to Maximum Utilization, Identifying Safest Drilling Operating Window
Authors: Rodriguez Freddy Rojas , Prasetia Andi Eka , Mettai Adel , Umar Lawrence , Thiam Yap Yun , Murad M. Syazwan 
Published: June 2014

Abstract
TTD-1 has been identified as the deepest HPHT well ever drilled by PCSB in Malaysia. Managed Pressure Drilling (MPD) enabled the Operator to drill and explore new sands and confirm new hydrocarbon reservoirs at 325 degrees F with an undisturbed bottom hole pore pressure of nearly 15,000 psi. The MPD technique in conjunction with the best HPHT practices was able to overcome challenges while drilling this exploration well. Challenges included:
Abnormal pressure ramp-up (greater than 17 psi/ft) High pore pressure steps in new sands Identifying and controlling wellbore breathing Controlling losses on the HPHT tight window zone
Technology and practices, including well control, HPHT drilling practices, pore pressure prediction and MPD, were integrated by the Operator during the planning and execution stages. The focus was to integrate MPD and HPHT procedures as well as optimize the available tools to maximize daily drilling footage and maintain the integrity of the well at all times. Annular friction losses (greater than 800 psi) were offset by Surface Back Pressure (SBP) to maintain constant bottomhole pressure (BHP) at all times, except instances when the annular backpressure was reduced for short periods to perform dynamic flow checks. Dynamic flow checks were performed every 45 feet measured depth to map the pore pressure. One of the dynamic flow checks identified one pressure step increase (greater than 1.0 ppg) and a 0.5 bbls gain on the trip tank at the same time. The dynamic formation integrity test (FIT) was successfully implemented to identify the upper limit of the operating window.
Proper application of these MPD procedures identified the minimum operating window as 1.0 ppg and guided the Operator to call for TD of the well. The well was drilled to a depth of 4,830 m, and thus penetrated vast gas bearing reservoirs. This technical paper aims to share a case study of HPHT drilling practices combined with Automated MPD successfully adopted to explore new sands with minimal offset geological and petrophysics information.
The Majnoon Field - A Case Study of Drilling Operations in a Remote Area of Iraq
Authors: Le Vesconte Marc-Jan , Tinkhof Rob , Hardman Paul 
Published: June 2014

Abstract
Iraq presents many challenges to international oil and gas producers. This paper will discuss one such operation, the giant Majnoon oilfield. The field was discovered in 1975. Following the drilling of 20 wells, operations were suspended due to the Iran-Iraq war of the 1980's. After the war, production resumed, however drilling did not re-commence until 2011.
The challenges of Majnoon are many: unexploded ordnance litters the field; (total) losses in the 12 ¼" hole; logistics require extensive planning and all drilling is undertaken by rigs with less experienced crews. Operator's tendering guidelines required a turnkey arrangement between Operator and the main Contractor, leading to an intricate arrangement of sub-contracts. Limited offset data further challenged the drilling process, with a steep learning curve evident across the field. With different disciplines on the critical path to meet the production target date, associated simultaneous operations led to rescheduling and flexibility on the part of the drilling operations team.
Major success factors include a focus on performance; contract management; having the ideal team in place from day one; upfront planning and competence assurance.
The paper will discuss aspects of the drilling program, from the initial contracting strategy, through to the final well delivery. Following an assessment of learning from the early wells in the sequence, the evolution of the performance culture will be discussed. The working relationship between the operator's field team and that of the main Contractor will be examined, particularly given the turnkey nature of the operation. The realignment of the project objectives after the first three wells will also be addressed.
The aim of the paper is to present a case study of the complexities that arise, from operating in a country recovering from a troubled period. The intent is to share learning that may enable future operations in Iraq to avoid some of the operational pitfalls seen in Majnoon.
Constructing Difficult Colony Wash Lateral with Innovative Rolling Cutter Technology Improves Drilling Performance
Authors: Bruton Greg , Smith Mark , Mueller Levi , Ford Robert , Bits Smith 
Published: June 2014

Abstract
Efficiently drilling the lateral hole section through the abrasive Granite Wash reservoir sands in western Oklahoma and the Texas Panhandle creates a unique challenge. The highly heterogeneous formation was causing inconsistent PDC bit performance while constructing the 6-1/8" horizontal and thus damaging project economics. A study determined that improved ROI could be achieved by extending bit life in areas where poor drilling performance is expected. A detailed forensic analysis showed extensive cutter damage with abrasive wear being the most common dull characteristic. The cutter wear was causing short runs and frequent trips for bit change-out. To solve the problem required a new approach.
A fixed PDC element creates an inherent limitation because only a small portion of the cutter contacts formation and as the cutter wears, drilling efficiency declines. The resulting wear flat generates a high degree of frictional heat which breaks the diamond-to-diamond bond leading to accelerated cutter degradation. The situation is exacerbated by difficulty transferring weight-on-bit due to extended length lateral drilling.
An R&D 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 several different retention methods and developed a specialized fixed housing which is brazed into the bit blade. The PDC cutter is mounted on a circular shaft and fitted within the housing allowing 360° cutter rotation. The robust system holds the cutter/shaft assembly securely in the housing for superior reliability. The rolling cutter assembly has essentially the same OD as a standard PDC cutter for superior design flexibility and cutter placement options.
A new-style 6-1/8" PDC (MSiR613/MSiR713) was manufactured with rolling cutters strategically positioned in the shoulder area. It has been run over 45 times in the Granite Wash formation and is delivering positive results. On a steerable motor, the RC equipped bit has increased total footage, hours on bottom and ROP compared to direct offsets drilled with fixed cutter PDC.
Drillstring Network 2.0: An Enhanced Drillstring Network Based on 100 Wells of Experience
Authors: Pixton David , Craig Andrew 
Published: June 2014

Abstract
Wired drill pipe (WDP) has been used in over 100 wells worldwide to provide high-bandwidth communications between the surface and tools deployed in the wellbore. Such enhanced access to real-time data improves decision making, opens the door for advanced drilling processes such as automated drilling, and gives visibility to downhole conditions where never before possible.
WDP creates a high-speed drillstring network at the wellsite that operates independently of drilling fluid, enabling communications for the widest range of drilling applications and conditions. In addition, the network provides real-time memory/wireline-quality data not only from tools in the bottom hole assembly but also from tools that may be arrayed at intermediate points along the drillstring. These and other attributes of a drillstring network are compelling given the drilling challenges encountered in today's wells. Indeed, the numerous deployments in which wired drillpipe has been used have demonstrated that the network provides significant value to the drilling process in terms of drilling safety, efficiency and performance.
Learnings and experience gained across these operations have driven the development of a new and enhanced version of the drillstring network. This second generation high-speed drillstring network includes improvements to the design of wired drillpipe, a new generation of distributed network electronics, and a graphical surface network controller. These enhancements and their utility with respect to improving drilling processes are discussed here in detail.
These improvements are designed to create a more stable, robust and reliable network system. Further, the enhanced graphical surface controller expands network diagnostic capabilities and reduces the learning curve for network users. Revisions to the wired drillpipe design will result in lower cost of ownership and more cost-effective deployment of the technology, further improving the value the system can provide.
An Engineering Look at the Cause of the 2010 Macondo Blowout
Authors: Turley John A. 
Published: June 2014

Abstract
This paper examines engineering and operating activities during post-discovery temporary abandonment of the Macondo exploration well that led to and caused the 20 April 2010 blowout and oil spill in the Gulf of Mexico. The paper ignores finger pointing and hearsay evidence and focuses on data generated on the Deepwater Horizon drilling rig. The forensic trail defines events that caused and exacerbated a down-hole leak between the pay zone and the lower casing. Subsequent pressure testing of the wellbore revealed the leak, but the well was declared secure. In further preparation for temporary abandonment, seawater was pumped down a work string to displace heavy mud from the wellbore and riser. Such displacement caused the well to flow from the formation, down the annulus, up the casing, above the blowout preventers (BOP), into the riser, up to the rig, and over the derrick. Crews immediately closed two BOPs, albeit too late to stop the massive flow from within the mile-long riser. Subsequent explosions and fire killed eleven, sank the rig, and marked the beginning of one of the most lethal, costly, manmade, environmental disasters in US history. Had industry protocol been followed, and/or had the forensic data that pointed to the leak or flow been acted upon, the leak would have been repaired and isolated, the wellbore would have been retested to prove pressure security, and the temporary abandonment would have proceeded as planned.