bluuebunny/crossref_metadata_2025_split huggingface dataset:
Designing and Implementing a Competency-Based Development Program for Iraqi Graduate Engineers
Authors: Saadawi Hisham , Al Sammarrai Wathik 
Published: October 2014

Abstract
A consortium made of PetroChina, Total and Petronas signed an agreement with the Iraqi government to develop the giant Helfaya field, Iraq. In 2012, PetroChina recruited 21fresh Iraqi graduates of different engineering disciplines to integrate them into the Company operations. They were graduates from the various local universities and colleges across Iraq.
It was evident that a traditional training program similar to what is used by many companies in the oil industry would not be suitable for the Iraqi graduates. A competency-based development program was specifically designed for Halfaya field operations and the needs of the newly recruited graduates.
This paper describes the approach adopted in designing this program, the key features of the program and the implementation experience.
Iraq has the world's second largest proven reserves of conventional crude oil after Saudi Arabia. While there are many publications on the technical aspects of the Iraqi oil industry, there is very little published on the development of Iraqi professional work force. This paper is a contribution towards bridging this gap. It provides a case study on how to design and implement a competency-based graduate development program tailor-made for Iraqi graduates.
Waterflooding Surveillance and Optimization for a Super-Giant Carbonate Reservoir
Authors: Wei Chenji , Li Yong , Song Benbiao , Zhou Jiasheng , Li Baozhu , Zhang Weimin 
Published: October 2014

Abstract
Waterflooding performance determines the recovery and life cycle of carbonate reservoirs. This paper presents a waterflooding surveillance and development plan optimization of a super-giant carbonate reservoir, which is a Cretaceous carbonate reservoir in Middle East, with OOIP of 4000 MM bbls.
This carbonate reservoir started to produce since 1970's without any energy supply, and the current reservoir pressure is just above the bubble point pressure. Therefore, water flooding project has been launched over the past 2 years. We presented a method to integrate the geology, production and injection data, PLT (Production Logging Test), saturation test, and pressure test. Based on the valuable data, we presented a comprehensive surveillance of the water flooding project and the careful evaluation about its effect. Then, based on the surveillance, reservoir simulation is conducted to optimize the pressure maintenance target, production rate, well pattern, well spacing etc. for different types of formation, and eventually an optimized development plan is proposed.
Workflow of waterflooding surveillance is established, and results and analysis for this field are shared. Important information such as the main flow direction of water and increased reservoir pressure are determined. Productions of several oil wells near the injectors are enhanced more than 45%, which indicates that the effect of waterflooding is significant. In addition, optimized parameters are obtained from reservoir simulation, and some interesting observations are found, such as that if we maintain the reservoir pressure just below the bubble point, the recovery is one of the best of the 6 scenarios. Furthermore, the optimized development plan increased more than 15% oil recovery compared with the base development strategy.
This study offers a comprehensive case study that supports engineers and geologists for better understanding the formation, monitoring the waterflooding process, and optimizing production plan on this carbonate.
Stick-Slip Detection and Friction Factor Testing Using Surface-Based Torque and Tension Measurements
Authors: Lai Stephen W. , Wood Mitch , Eddy Aaron , Holt Trevor , Bloom Matthew 
Published: October 2014

Abstract
Recently, there has been a strong push towards automation and the use of real-time models in the drilling industry. However, it has been recognized that these new methods require a drastic improvement in the quality of sensor data gathered at the rig. In this paper, we investigate how accurate measurement of drill pipe torque and tension at the surface can be used to diagnose downhole conditions.
A surface-based torque and tension sub was used to perform measurements while drilling several extended reach horizontal wells in the Dilly Creek area of the Horn River Basin. A filtered version of surface torque was used to calculate a stick-slip metric which was compared to stick-slip measurements using a downhole tool. The results show that there is reasonable correlation between surface and downhole metrics, but the correlation is highly dependent on torque filter stop frequency. A comparison is also performed between the hookload measured with a deadline sensor and the tension measurement from the surface sub. The results show a systematic discrepancy of approximately 5% that is likely due to sheave friction. A commercial torque and drag software package is used to show that values for casing friction factor may be underestimated if sheave friction is present but ignored in the analysis.
Controlling Extreme Fluid Loss During Workover Operations in Dual-Porosity Reservoirs with Hydraulically Induced Fractures
Authors: Delgado Eduardo , Crespo Freddy , Zabala Richard 
Published: October 2014

Abstract
Fluid losses during overbalanced well interventions particularly in depleted and under-pressured formations can become excessive in the presence of naturally occurring fractures, vugs, and caverns. Such features in combination with hydraulically induced fractures pose a set of issues that contribute heavily to the amount of fluid being lost into the formation. In this type of scenario it is not uncommon for the rate of fluid loss to exceed available pumping capabilities.
This paper highlights the successful design and implementation of a robust pill to control excessive completion fluid losses, minimize formation damage in dual-porosity reservoirs with hydraulically induced fractures, while contributing to improve injection profile. This treatment contains a low-viscosity, solids-free, relative permeability modifier system coupled with biodegradable natural cellulose fibers for lost circulation control during workover and drilling operations.
This system was applied to a cased-hole oil producer completed in the presence of natural and induced fractures (4500 psi, 15,500-ft TVD, and 270°F) in the Mirador, Barco, and Guadalupe formations in Colombia. This well was intended to be converted from a high-water cut producer into a gas injector to support field revitalization. Also, better access to the Barco and Guadalupe formations was desired to increase the injection profile. Excessive fluid losses during the workover made it impossible to carry out operations as planned. Ten pills of different conventional lost circulation materials (LCM) were implemented with no success. There was still a need to reduce losses below 10 bbl/hr to continue.
Two 50-bbl pills of the proposed treatment were spotted to the target zone. Losses were immediately decreased to 9.1 bbl/hr on the first attempt, enabling continuation of the interventions with no further non-productive time (NPT). After completion, the well was successfully cleaned-out with nitrogen through coiled tubing (CT), and after two months, efficient gas injection was started as planned with the desired injection profile and no signs of further damage.
A Semi-analytical Solution to the Transient Temperature Behavior along the Wellbore and Its Applications in Production Management
Authors: Xu Boyue , Wu Xingru , Gao Yonghai , Ling Kegang 
Published: October 2014

Abstract
Temperature measured from a permanent downhole gauge in a well after the well shut-in provides a unique perspective for surveillance and production management purposes. For example, in deepwater environment, production engineers need to know the temperature status of a shut-in well before it is being restarted since different temperature profiles along the wellbore may need very different restarting strategies for flowing assurance purposes. A number of "rule-of-thumb" or complicated numerical simulations are either not reliable or impractical.
This paper presents a semi-analytical model to estimate the temperature transient behavior after the well shut-in. The model is solved numerically through inverse Laplace transform and integration. This solution gives temperature distribution profile and history in any location along the radial direction for a given production time and shut-in duration. To make it more general for other wells, an empirical correlation is provided through regression on the calculated type curves. The difference between this semi-analytical solution with other previous efforts will be discussed.
The applications of the solution to this model are multiple folders. For example, we can use the solution to predict the temperature behavior after the well shut-in, which can be used for flow assurance purposes. Furthermore, matching the calculated temperature with the measured temperature at the same location will yield the well local heat transmissibility coefficient. Some field examples are provided to demonstrate these applications.
Integration of Principal-Component-Analysis and Streamline Information for the History Matching of Channelized Reservoirs
Authors: Chen C. , Gao G. , Honorio J. , Gelderblom P. , Jimenez E. , Jaakkola T. 
Published: October 2014

Abstract
Although Principal Component Analysis (PCA) has been widely applied to effectively reduce the number of parameters characterizing a reservoir, its disadvantages are well recognized by researchers. First, PCA may distort the probability distribution function (PDF) of the original model, especially for non-Gaussian properties such as facies indicator or permeability field of a fluvial reservoir. Second, it smears the boundaries between different facies. Therefore, the models reconstructed by PCA are generally unacceptable for geologists.
A workflow is proposed to seamlessly integrate Cumulative-Distribution-Function-based PCA (CDF-PCA) and streamline information for assisted-HM on a two-facies channelized reservoir. The CDF-PCA is developed to reconstruct reservoir models using only a few hundred of principal components. It inherits the advantage of PCA to capture the main features or trends of spatial correlations among properties, and more importantly, it can properly correct the smoothing effect of PCA. Integer variables such as facies indicators are regenerated by truncating their corresponding PCA results with thresholds that honor the fraction of each facies at first, and then real variables such as permeability and porosity are regenerated by mapping their corresponding PCA results to new values according to the CDF curves of different properties in different facies. Therefore, the models reconstructed by CDF-PCA preserve both geological (facies fraction) and geostatistical (non-Gaussian distribution with multi-peaks) characteristics of their original or prior models. Our preliminary results indicate that the history-matched model using the CDF-PCA alone may not satisfy the requirement of geologists, e.g., some channels may become disconnected during history-matching. Therefore, we propose a method of combining CDF-PCA together with streamline information. Because velocity of the tracer in the streamline provides connectivity information between injectors and producers, it enhances channel connectivity without over-correction on cell-based permeability during the process of history matching.
The CDF-PCA method is applied to a real-field case with three facies to quantify the quality of the models reconstructed. The history matching workflow is applied to a synthetic case. Our results show that the geological facies, reservoir properties, and production forecasts of models reconstructed with CDF-PCA are well consistent with those of the original models. The integrated HM workflow of CDF-PCA with streamline information generates reservoir models that honor production history with minimal compromise of geological realism.
Breathing a New Life for Kinabalu – A Showcase of Operatorship Handover, Field Rejuvenation and Operational Synergies for a Mature Oil Field in Malaysia
Authors: Othman Mohamad , Masoudi Rahim , Pilus Azmi 
Published: October 2014

Abstract
The Kinabalu oil field is located offshore Sabah, Malaysia was relinquished to PETRONAS after the expiry of the Production Sharing Contract (PSC) at the end of 2012 after 15 years in production. As common to other matured fields, Kinabalu was experiencing many sub-surface and operational challenges that need to be overcome in order to realize the field full potential. The challenge for PETRONAS as the host authority and resource owner is to select the new operator with proven field redevelopment and mature asset management expertise to take over the operatorship. The new operator should also have the mature field mindset and expected to maximize hydrocarbon recovery through major capital investment, reduce the production cost through operational efficiency and synergies and mature the upside potential. As the host authority it is imperative for PETRONAS to incentivize the operator to continue to identify opportunities to grow the asset through innovative Petroleum Arrangement.
The paper showcases, the successful collaboration efforts between the host authority, the operator and the partner to overcome various challenges to add value to this mature asset through smooth operatorship handover, field redevelopment plans and operational synergies between operators in the South Sabah region. The paper will highlight the role played by the host authority to incentivize and influence the operators to execute the field rejuvenation effort and to realize the potential of a mature field. The paper will discuss the key challenges in the planning and execution of fast track field development to rejuvenate the field and to increase the oil production from 7,000 bopd to 20,000 bopd. The paper will also discuss an integrated operating model to facilitate more efficient and effective utilization of existing and planned infrastructure, improve facilities uptime and reduce the overall operating and development costs for the mutual benefit of operators in the region.
The successful effort to breathe a new life to Kinabalu field marked a significant milestone for the Malaysian oil and gas industry. This is also the first time in the history of the Malaysia oil industry that the asset and the operatorship was transferred from one International Oil Company (IOC) to another IOC. A new innovative Petroleum Arrangement (PA) was adopted for the first time for the matured field PSC in Malaysia to incentivize the PSC operator to grow the asset. The results and lessons learned from the project are crucial in the other future field operatorship handover and mature field rejuvenation in Malaysia.
A Novel Way to Spot and Squeeze a Lost Circulation Cement Plug Using Managed Pressure Drilling Techniques in HP/HT Conditions: Case History from the Mediterranean Sea
Authors: Bhaisora Devesh , Waheed Arshad , Gawad Mohamed Abdel , Hollman Landon , Fayed Mohamed Idris , Mehdiyev Akshin , Geldof Wilco 
Published: October 2014

Abstract
Curing losses during drilling is a widely known and discussed topic. Losses are mainly cured by spotting a lost circulation pill from the mud company or by spotting and squeezing a lost circulation cement plug. Many papers have been published regarding the composition of lost circulation pills, which is considered one of the key success factors. However, the technique used to place these pills in a zone of interest also can be tricky and equally contributes to the success of the job.
In most cases, a cement plug is spotted using the traditional balanced plug method. However, in high-pressure/high-temperature (HP/HT) wells having a very narrow margin between pore pressure and fracture gradient, there is very little probability of spotting a balanced cement plug successfully under lost circulation conditions. In the above mentioned situation, spotting any cement plug becomes a critical application. The correct amount of annular pressure required during the spotting of the plug must be calculated precisely, as even minor differences in applied surface pressure can damage the downhole stability of the cement plug.
BG Egypt recently experienced complete losses, resulting in a loss of more than 1,000 bbl of oil-based mud (OBM) in the Miocene section while drilling a HP/HT well offshore in the Mediterranean Sea. The immediate loss in hydrostatic pressure reduced the equivalent mud weight (EMW) on bottom and required the response of the managed pressure drilling (MPD) system to apply sufficient annular pressure to control the well by spotting lost circulation material (LCM) pills and a cement plug at desired depths. This paper discusses the novel approach used to successfully spot and squeeze a LCM pill and cement plug in a HP/HT situation with a narrow pressure margin using an MPD system, which resulted in reduced mud losses, increased success of the LCM pill and cement plug setting, and reduced time required to fully manipulate the EMW on bottom.
In-Situ Wettability Utilizing Low Gradient Magnetic Resonance
Authors: Jebutu Segun , Li Weidong 
Published: October 2014

Abstract
Hydrocarbon recovery, production mechanisms and field development economics strongly rely on understanding the wetting characteristics of the in-situ reservoir fluids. In the Gulf of Mexico reservoir systems presented, we characterize and profile the occurrence of mixed wettability conditions. This paper presents a new approach to estimate wettability, utilizing low-gradient magnetic resonance technology. Core data, core flood experiments, advanced fluid sampling and dynamic temperature anomaly evaluations are integrated to investigate the pore-scale complex fluid distributions and connectivity of varying wettability systems.
Wettability is difficult to measure in-situ, however the interaction of the fluid and rock mineral surfaces have an apparent relaxation time that is influenced by the surface relaxation mechanism of magnetic resonance. Wettability can be measured in the laboratory through contact angle, atomic forces microscope imaging and Amott index measurements. These are scale-constrained and it is difficult to replicate original down-hole conditions for these measurements. The new approach enables direct wettability estimation at in-situ reservoir conditions.
A spin-lattice function is derived, which is directly related to the interfacial tension and surface wetting fluid properties. A wettability index is then computed from the function using a reference zone below the free water level. The results indicate mixed wetting characteristics in asphaltenes and heavy-to-solid hydrocarbon-bearing sections. Several other factors evaluated that may account for the wettability distribution include asphaltene content of oil, acid number of the oil, rock surface roughness estimated from grain size modeling, and paleo-diagenetic thermal and pressure history of the reservoir. A more significant challenge for production performance from mixed wet systems is the connectivity of the wetting phases that may aid or impair mobility of fluid displacement, which can now be characterized by a depth-continuous wettability. The early knowledge of the presence of mixed wet system allows for optimal development planning of future recovery methods.
Rigorous Modeling for Data Analysis towards Accurate Determination of Shale Gas-Permeability by Multiple-Repeated Pressure-Pulse Transmission Tests on Crushed Samples
Authors: Civan Faruk , Devegowda Deepak 
Published: October 2014

Abstract
Determination of the nanodarcy gas permeability and other parameters of shale by pressure-pulse transmission testing of core plugs, drill cuttings, and crushed samples is discussed. The methods available for interpretation of pressure-pulse decay tests are reviewed with emphasis on the difference between the intrinsic and apparent permeability. Improved formulation and analysis which honor the relevant physics of gas transport and interactions of flowing gas with the shale under the pore-proximity and elevated pressure conditions are presented. Modification of the shale and fluid properties under prevailing stress, and pore-size distribution, connectivity, and confinement conditions is shown to be important under any pressure conditions while the gas rarefaction and slippage effects diminish essentially at high pressures but become important at low pressures. The permeability and other parameters of shale samples are determined by numerical modeling and analysis of the pressure tests conducted under different conditions in order to accommodate for temporally and spatially variable conditions. Better design and analysis of experiments for simultaneous determination of several unknown parameters that impact transport calculations, including stress-deformation, adsorption, diffusion, and deviation from Darcy flow are described. The inherent limitations of the earlier methods which rely on the approximate analytical solutions of the simplified diffusivity equation based on the Darcy's law are delineated. It is pointed out that the permeability measured using a Darcy-type equation is the apparent permeability and not the intrinsic permeability. Thus, the primary reason for the contradictory values of permeability measured by application of the analytical models is explained by dependence of the permeability of shale to different testing conditions over which only different average permeability values can be obtained when applying the approximate analytical solutions obtained based on the assumption of a constant permeability value.