bluuebunny/crossref_metadata_2025 huggingface dataset:
Model Dinamik Pengelolaan Jasa Ekosistem Waduk Koto Panjang Kabupaten Kampar Riau
Authors: Warningsih Trisla , Setiyanto D Djoko , Fahrudin Achmad , Adrianto Luky
Published: January 2017

The study aims to establish the management model of ecosystem services Koto Panjang Reservoir.The approach used in this modeling is the Dynamic Modelling. The results showed the value ofprediction error of the simulation results based on the data used was in the range 0.4 % - 4.64 %. Thesimulation results show the value of economic growth in 2020 will reach its peak value Rp.3,3 billion.The economic value of the total economic value of the four main activities of the utilization ofecosystem services Koto Panjang Reservoir namely; KJA cultivation of Rp.1,1 billion, tourism Rp.1,6billion,  fishing by paddle for 60 million,  fishing by fishing boat engine at Rp.489 million. Modelscenarios developed by increasing the KJA growth of 30% and 100% for tourism, managed toincrease the total economic value of Rp.5,08 billion from previously around Rp.3,3 billion or anincrease of approximately 53.95%. The increase in the economic value derived from an increase inthe economic value of Rp.1,56 billion KJA activities and improvement of the economic value oftourism activities Rp 2,9 billion.  Keywords: ecosystem services, reservoirs, total economic value, dynamic modelling
Status Populasi Bulu Babi Tripneustes gratilla di Perairan Desa Liang, Pulau Ambon
Authors: Uneputty Prulley A , Pattikawa Jesaja A , Rijoly Frederick
Published: January 2017

Research to study status of sea urchin Tripneustes gratilla was carried out at the coastal waters of Liang Village, Ambon Island on September 2012. Belt transect method with the plot witdh 10m was used in this study.It was found that density of T. gratilla in in the area was 0.0122 ind./m with the highest density occurred at transect 1 i.e. 0.016 ind./m 2 . Estimated potential of T. gratilla was 4760 individuals. Based on the size of 145 individuals sampled, mean diameter of T. gratilla in Cape Matiella was 68.35mm and it was ranging from 58.11 mm to 76.61mm. Those sizes of diameter could be grouped into 2 age groups (cohorts) with the mean size of first and second cohorts were 64.51mm and 72.28mm, respectively. In general, length (diameter) – weight analysis showed that growth pattern of sea urchin in the area was negative allometric in which diameter grown faster than weight with the exception of sea urchin in transects 3 and 4 which showed isometric growth i.e. increasing of diameter was proportional to weight.Keywords: Tripneustes gratilla, density, cohort, length-weight relationship 2 while the lowest occurred at transect 4 i.e. 0.009 ind./m 2
Maskulinisasi Ikan Nila Melalui Perendaman Larva pada Suhu 36 °c dan Kadar Residu 17a-metiltestosteron dalam Tubuh Ikan
Authors: MD Afpriyaningrum , DT Soelistyowati , D Hardiantho , Alimuddin Alimuddin , M Zairin Jr , M Setiawati
Published: January 2017

The residue of 17a-methyltestosterone (MT) in fish has been a concern related to food and the environment safety. This study aimed to determine sex ratio of Nile tilapia treated by MT immersion at 36 °C water temperature, and measure the level of testosterone in fish body. Three hundreds of ten-day-old post hatched larvae was immersed in one liter of water containing 2 mg MT, at 26 °C and 36 °C. Immersion was performed for 2 and 4 hours. The results showed that immersion at 36 °C and increasing immersion time increased male percentage. Higher male percentage was obtained in treatment 4 hours immersion at 36 °C (92.5% male) and the effective treatmen 4 hours immersion at room temperature. By ELISA method, testosterone level in MT treated fish decreased sharply to 88.2% at one month after immersion, and being the same as control without MT immersion. Thus, masculization in tilapia could be performed by MT immersion at 36 °C water temperature for 4 hours, and it is most likely that no MT residual in fish after one month post immersion. Keywords: Nile tilapia, sex reversal, temperature, 17a-methyltestosterone
Technology Update: New Perforating Gun System Increases Safety and Efficiency
Authors: Salt Warren , Galka Ned , Segura John
Published: January 2017

Technology Update

Achieving greater efficiency in perforation systems can help lower operating costs, particularly when completing long horizontal wellbores in unconventional plays.

The DynaStage perforating system, developed by DynaEnergetics, incorporates new technology in the addressable firing system and an improved mechanical design that eliminates potential human error. The system can operate more efficiently than traditional systems and, with its additional safety features, allow other wellsite operations to run in parallel with the perforation process.

As a result, the system can achieve improvements in perforation quality and performance reliability, with fewer misruns, while operating efficiently enough to lower total completion costs. The DynaStage system has successfully completed field trials in multiple basins and been commercialized.

The system targets two areas to improve operational efficiency and reduce operating cost.

Safety—the system has a simple, intrinsically safe design that eliminates the risk of inadvertent detonation from stray current or voltage. Surface explosive handling and arming can be conducted in less time and in parallel with other operations. The design eliminates the need to hold the gun system at shallow subsurface depth during simultaneous operations. Both factors reduce wait times at the wellsite.

Reliability—the design of the electronic system and simplification of the mechanical field assembly process help to reduce the number of misruns, which increases efficiency and lowers the cost of completions.

Surface Assembly

Perforating operations with explosives place the explosive components and workers in close proximity, especially during the arming process. Traditional resistorized detonators can contribute to an increased risk of injury and destruction when connecting the detonator to the gun string and the wireline truck.

Safety procedures have been developed to address the risks in this process, and the American Petroleum Institute (API) provides guidelines for safe handling of explosives through Recommended Practice 67 (API RP 67). One of the established best practices is to suspend all surface operations while working with the resistorized detonators. The arming and connection of a gun string at the surface can take up to an hour, meaning that no other wellsite operations can be completed during this time.

The DynaStage system removes the risks of this process by providing an addressable and radio frequency (RF)- safe system with immunity to high voltage and current levels. The firing system is built on a low-voltage, digital communication platform that uses the DynaEnergetics detonator technology, proven to successfully communicate and initiate on command during more than 300,000 perforating operations, without a safety incident. This technology enables the verification of all components in the system, including the addressable switch, the RF-safe detonator, and the RF-safe ignitor, during all phases of the operation.
Intelligent-Completion Installations in the Santos Basin Presalt Cluster
Authors: Wilson Adam
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 174725, “Road to Success and Lessons Learned in Intelligent-Completion Installations at the Santos Basin Presalt Cluster,” by E. Schnitzler, D.A. Silva Filho, F.H. Marques, F.K. Delbim, K.L. Vello, L.F. Goncalez, and T.C. Fonseca, Petrobras, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28-30 September. The paper has not been peer reviewed.

This paper presents information regarding the installation of intelligent-well completions (IWCs) in the Lula and SapinhoÁ fields of the Santos basin presalt cluster (SBPSC). The technology is intended to improve reservoir-management capability by using remotely operated flow-control valves and real-time pressure and temperature monitoring for each perforated interval, corresponding to different reservoir zones. The benefits are obtained at the expense of additional challenges for well engineering because well-completion design becomes more complex and overall associated risks increase.

Introduction

The area known as the presalt cluster in the Santos basin is located in ultradeep waters, between 1900 and 2400 m, approximately 290 km from Rio de Janeiro in southeast Brazil. Fig. 1 shows the main blocks of the presalt cluster currently in the appraisal-plan or production-development phases.

The first areas selected for production development were Tupi (BM-S-11 Block) and GuarÁ (BM-S-9 block), which now are known as the Lula and SapinhoÁ fields. Initially, extended well tests were performed in these areas to gather information and test some of the technologies that would be applied on further developments. Later, a production pilot project was initiated in Lula field by the deployment of a production system with a total of nine wells (six producers and three injectors). Since then, new production systems are being deployed continually in the Lula and SapinhoÁ fields.

Since the SBPSC initial phases, IWC was considered one of the more appropriate designs for production-development projects in the field. This technology is expected not only to improve reservoir management but also to provide better capabilities to deal with reservoir uncertainties, which is imperative in carbonate reservoirs.

Intelligent-Completion Systems

Internal risk-analysis assessments before the first production-development project supported the decision to use a two-zone hydraulic system to actuate the inflow-control valves (ICVs). The choice was based on the advice of specialists who considered it to be the simplest and most reliable system in the long term and recognized that it is a field-proven solution. On the other hand, wet trees designed for SBPSC projects contain a multiplex control system, which adds additional integration issues to be addressed during the planning phases.
The HP/HT Completion Landscape
Authors: Carpenter Chris
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170919, “The HP/HT Completion Landscape—Yesterday, Today, and Tomorrow,” by Douglas J. Lehr and Scott D. Collins, Baker Hughes, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed.

The methods used for high-pressure/ high-temperature (HP/HT) tool development are evolving, and development cycles are lengthening, particularly for ultra-HP/HT applications (those involving pressures greater than 15,000 psi or temperatures greater than 350°F) in which materials screening and stability assessments are required. What can the industry anticipate for future HP/HT wells in terms of architecture, product development, and regulatory challenges? This paper identifies current development paradigms and discusses the future challenges in well planning, product development, and regulation.

HP/HT Completion Technology Challenges

The technological challenges associated with the completion of wells at and above HP/HT conditions are diverse and continue to increase. Previous investigations into HP/HT projects identified technology gaps related to packers, bridge plugs, liner hangers, subsurface safety valves (SSSVs), tubing-to-packer seals, and related products. (Please see the complete paper for a comprehensive list of challenges faced in HP/HT environments, as well as a discussion of the historical perspective in HP/HT well development.)

In addition to the general challenge of materials design and testing for HP/HT environments, several specific component-based challenges also exist.

Packers. Packers and bridge plugs have been developed for service conditions as challenging as 500°F and 25,000 psi, but the primary difficulty in the development process today is the availability of materials, both metallic and nonmetallic, which are suitable for very high levels of stress and strain and which possess the desired corrosion resistance to achieve longevity requirements.

SSSVs. SSSVs contain many dynamic seals which must maintain their integrity and operating characteristics over the life of the completion. Also, the operator must have the capability to extend the life of a malfunctioning safety valve through the use of “insert valves.” These are smaller-diameter wireline-conveyed valves that can be run and inserted into the bore of the tubing-mounted safety valve so that production can continue under fail-safe conditions.
Streamline-Based History Matching for Multicomponent Compositional Systems
Authors: Carpenter Chris
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 174750, “Streamline-Based History Matching of Arrival Times and Bottomhole-Pressure Data for Multicomponent Compositional Systems,” by Shusei Tanaka, Dongjae Kam, Akhil Datta-Gupta, and Michael J. King, Texas A&M University, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.

Streamline-based history-matching techniques have provided significant capabilities in integrating field-scale water-cut and tracer data into high-resolution geologic models. However, application of the streamline-based approach for simultaneous integration of water cut and bottomhole pressure (BHP) has been rather limited. In this paper, the authors introduce a novel semianalytic approach to compute the sensitivity of the BHP data with respect to gridblock properties.

Introduction

The streamline-based method has many advantages in terms of computational efficiency and applicability. The main advantage of the streamline-based method is that it is able to calculate parameter sensitivity with a single streamline simulation or post-processing of the grid-based finite-difference simulation results. The calculated sensitivity is comparable with the sensitivities computed from numerical perturbation or with adjoint-based sensitivities. It is possible to calculate the parameter sensitivity from a commercial finite-difference simulator by use of streamlines traced using the flux field. This allows accounting for detailed physics by means of finite-difference simulation while taking advantage of the power of the streamlines for sensitivity computations.

Streamline and Parameter Sensitivity

Streamline-based history matching starts with the tracing of streamlines from a given set of static and dynamic conditions. This process is outlined in detail in the complete paper.

Amplitude, Travel-Time, and Generalized Travel-Time Inversion (GTTI) Methods

The approach to minimizing the objective function through all the observed points and simulation results is defined as amplitude inversion. The travel-time inversion, instead, attempts to match single reference times such as water-breakthrough point or peak tracer response. The amplitude matching is general in terms of reduction of the objective function, because while the travel-time inversion reduces the objective function at only a single point, the amplitude matching can cover all the data points. However, the travel-time-based approach is often used because amplitude inversion is a highly nonlinear problem and presents difficulties in computational cost and in reducing the objective function when there is a large amount of wells and data points.
Improving People’s Lives: Hope Is Not a Strategy … But Without Hope, There Is No Strategy
Authors: Meehan Nathan
Published: January 2017

President's column

A great benefit of being the SPE president is the chance to interact with students and young professionals around the world. Many are anxious about the future, but not panicked. I have been asked if this is the worst time ever in the oil business, a question that made me smile.

For some reason, it is natural to try and “scale” a current calamity with past ones. For example, financial recessions are compared with the Great Depression of the 1930s during which the worldwide gross domestic product (GDP) dropped 15% in 3 years. In comparison, the recession of 2008– 2009 saw a 1% drop in worldwide GDP but certainly felt huge. WTI crude oil prices dropped from USD 145.31/bbl on 3 July 2008 to USD 30.28/bbl in less than 5 months. The US rig count followed suit, dropping from 1,987 in August 2008 to 895 by mid-2009. It certainly was not good, but it was relatively short-lived.

Fig. 1 compares US rotary rig activity during the four most recent significant downturns. Leo Tolstoy’s quote about families may be paraphrased to apply to downturns: “Each oil price downturn is unhappy in its own way,” and each downturn and recovery had different causes. In Fig. 1, I have started with the peak US rig activity immediately prior to the beginning of the downturn and normalized subsequent weekly activity to this peak. Each prior downturn recovered to about 80% of peak activity within approximately 2 years after dropping from 45% to 55% of peak activity.

We are currently at less than 25% of the prior peak activity level and at an all-time low for the Baker Hughes reported US rig count dating to 1944. Compare this with the 1980s. In late 1981, rig activity peaked at 4,530 rigs and in the subsequent “ice age,” the rig count dropped to 663, less than 15% of the peak. While this was a steeper drop from the peak level, current rig activity is now approximately 70% of that ice age bottom, and future drops are certainly possible. Current rig activity is lower than what the US has seen in a very long time.

Is the Current US Rig Count the Lowest Ever?

I have been looking at historical rig activity measures. The Baker Hughes rig count data from 1944 include only rotary rigs. Before the 1950s, cable tool rigs accounted for a significant portion of drilling activity. Cable tool drilling dates to 1806 with horse-powered rigs. These were replaced in the 1830s by steam engines to provide rig power, and in 1860 when J.C. Rathbone used a steam-powered cable tool rig to drill a 100-B/D producer in West Virginia, cable tool activity took off. During the US Civil War, many hundreds of cable tool rigs were drilling, primarily in West Virginia, California, and Pennsylvania. If we include cable tool rigs, total US rig activity has exceeded 500 rigs since Abraham Lincoln was the US president, making the rig activity of 464 as of 24 March this year a truly historic low.
Technology Update: Biocide Treatment Program Reduces Premature Coiled Tubing Failures
Authors: Edillon Lemuel , Henderson Matthew , Leong Stan
Published: January 2017

Technology Update

Premature coiled tubing (CT) failures have occurred in the United States, in areas such as the Eagle Ford and Haynesville formations, and the Permian Basin. In Canada, these failures once were not considered as prevalent. However, a presentation at the 2015 SPE/ICoTA conference in The Woodlands, Texas, changed that perception. A paper presented there detailed how a major Canadian CT service provider experienced a series of CT string failures while performing bridge plug millout operations in the Montney formation in northeastern British Columbia (Edillon et al., 2015).

With each trip in or out of the wellbore, CT strings incur fatigue that can be estimated using simulation software based on the CT outside diameter (OD), material grade, and operating conditions. CT strings can fail for a variety of reasons, including external mechanical damage, corrosion, and excessive diametrical growth. Premature failure results not only in operational delays and the associated costs, but critical safety risks for onsite personnel.

For these reasons, a study was undertaken to determine the root cause of the CT string failures in the Montney. The results showed that microbial influenced corrosion (MIC) was a contributing factor. This led the CT service provider to instigate laboratory and field studies to create a biocide treatment program. The program has successfully mitigated further CT string failures in the Montney and has now been applied to CT programs in the Eagle Ford formation.

CT String Analysis

Seven failures of 60.3-mm (2.375-in.) CT strings supplied by multiple manufacturers were experienced over 2½ months. The strings failed in the range of 18% to 49% fatigue—well below their predicted 80% fatigue life. Preliminary analysis of the failure points revealed pinholes and internal corrosion in the base material and at the bias weld. The filler material used in bias welds has different mechanical properties than the base pipe material, making it weaker and more fatigue-prone.

To determine the failure mechanism, CT strings from four of the seven units were further analyzed by the manufacturers. In all four cases, internal corrosion pitting was observed. Comprehensive analysis on one string, including scanning electron microscopy, energy-dispersive X-ray spectroscopy, and metallography, was performed by the manufacturer and the University of Calgary. The analysis revealed that failure occurred at the bias weld and indicated microcorrosion pitting and transverse cracking in the weld filler material (Fig. 1). The corrosion morphology (rounded shape with light green corrosion debris) and the presence of sulfur in the corrosion product provided indirect evidence of MIC.
Stuck-Pipe Prediction With Automated Real-Time Modeling and Data Analysis
Authors: Carpenter Chris
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 178888, “Stuck-Pipe Prediction Using Automated Real-Time Modeling and Data Analysis,” by Kent Salminen, SPE, Curtis Cheatham, SPE, Mark Smith, SPE, and Khaydar Valiulin, SPE, Weatherford, prepared for the 2016 SPE/IADC Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. The paper has not been peer reviewed.

A real-time method is presented to predict impending stuck pipe with sufficient warning to prevent it. The new method uses automated analysis of real-time modeling coupled with real-time- data analysis. It can be applied to all well types for any well operation. The new method combines two types of analysis: (1) deviation of real-time data from real-time model predictions by use of hydraulics and torque-and-drag software, and (2) trend analysis of real-time data.

Data Types and Frequency

The approach taken was to first study real-time data sets from wells in which stuck-pipe incidents occurred and determine the root cause of each. The majority of these wells were drilled between 2009 and 2013 in the Eagle Ford shale. Specific patterns in the data were then identified as potential leading indicators of stuck pipe.

One of the first issues identified was that the type, frequency, and quality of data available are not consistent from well to well. To ensure that the alerting system was configured to work on different well types with a high degree of functionality, the decision was made that it would be designed to monitor a well and provide alerts even if only “critical” data streams are available. These critical streams would meet the following criteria:

Available on most rigs capable of capturing real-time data

Be useful in determining information about the drillstring, drilling fluid, and the wellbore itself

Fit within a logical progression that can indicate impending stuck pipe
Production Performance in the In-Fill Development of Unconventional Resources
Authors: Carpenter Chris
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 175963, “Production Performance in the In-Fill Development of Unconventional Resources,” by Bilu V. Cherian, Sanjel; Matthew McCleary, Samuel Fluckiger, Nathan Nieswiadomy, Brent Bundy, and Sarah Edwards, SPE, SM Energy; and Rafif Rifia, Kristina Kublik, Santhosh Narasimhan, James Gray, Olubiyi Olaoye, and Hamza Shaikh, Sanjel, prepared for the 2015 SPE/CSUR Unconventional Resources Conference, Calgary, 20–22 October. The paper has not been peer reviewed.

Data now show that the behavior of unconventional wells to in-fill drilling varies significantly across basins. A key influence may be changes in pore pressure and saturation (saturation history). This paper presents results from the analysis of the effect of in-fill drilling on parent-well performance, and describes a simplistic approach to understanding the effect of the quest for operational efficiencies and economic cycles on development strategies.

Methodology

This study focuses on two unconventional plays, the Eagle Ford and the Bakken. The objective was to model the well performance of the parent wells with the aim of matching and predicting in-fill-well performance. Because the two assets are at two significantly different portions of the development cycle (Eagle Ford is very early in its cycle), the Bakken data set has the luxury of modeling and matching the performance of the parent and in-fill, whereas the Eagle Ford portion of this study focuses on forward modeling and optimizing in-fillwell completions.

The methodologies used in this study (parent-well modeling, petrophysical models, geomechanics, fracture modeling, production modeling, and in-fillwell/ depletion modeling) are discussed in detail in the complete paper.

Bakken System Parent-Well Modeling

Petrophysics. The Middle Bakken member was divided into three main facies. Petrophysical evaluation indicates that average porosity and average water saturation were 8 and 50%, respectively, for the Middle Bakken. Average Klinkenberg permeability for the entire Middle Bakken is approximately 0.02 md. Mercury-injection capillary pressure curves indicate that irreducible water saturation is between 30 and 40% for rock with porosity between 1 and 7%. Residual oil is between 30 and 40%. Accordingly, the moveable fluid is low (20–40%), and hydraulic fracturing was recommended to stimulate more production.

The Three Forks formation was divided into five facies. Petrophysical evaluation suggests that the upper part of the Three Forks, Facies TF 23, has oil potential. Most facies are strongly affected by calcite and dolomite diagenesis, which allows alternating porosity development in some cases. In this area, the Middle and Lower Three Forks have higher water saturation, with very-low-permeability streaks (less than 0.007 md).
Technology Update: New Intelligent Completion System Enables Compartment-Level Control in Multilateral Wells
Authors: Dyer Stephen , Bouldin Brett
Published: January 2017

Technology Update

Although early inflow control devices and intelligent completions (ICs) were introduced almost 20 years ago, completion technology has not kept pace with advancements in drilling technology.

Today, wells completed in multilayered reservoirs, multilaterals with compartments of varying pressure, and extended-reach drilling (ERD) with wellbores as long as 12 km are becoming common. In complex, hard-to-reach reservoirs and tighter formations, operators need to maximize reservoir contact in every well to optimize reservoir drainage and minimize costs. Yet the evolution of ICs has lagged, creating a technology gap with significant ramifications.

IC reliability has been steadily increasing over the years, reaching more than 97% for the life of the well in many applications. Most permanent downhole monitoring and control solutions still consist of a separate “kit” of products rather than an integrated system.

Traditional IC systems lack sufficient real-time measurements in individual producing zones to facilitate “cause and effect” decision making. Without detailed compartmental information and control in case of water or gas breakthrough, operators are forced to restrict production, intervene, and in some instances work over the entire well.

Until recently, there has been no way to maintain production from other unaffected zones during the long diagnostic process of production logging, well testing, interpretation, and execution of an appropriate well intervention. The typical optimization cycle substantially raises operating costs while delaying vital production for weeks or months. Consider Saudi Aramco’s experience with ICs in remote oil fields, where tight formations and a shortage of suitable surface locations drove the need to dramatically increase reservoir contact per wellhead.

Before 2007, the company had successfully drilled and completed a number of multilateral ERD wells, achieving more than 5 km (16,400 ft) of reservoir contact per well. These maximum reservoir contact (MRC) wells were completed with then state-of-the-art IC technology. Completions consisted of permanent downhole gauges (PDGs) and downhole flow-control valves (FCVs), which could be partially or fully opened or closed by hydraulic control lines from the surface. Monitoring and control stations were installed in the motherbore above the junction to each side lateral.
Scaling Up Smart Water
Authors: Rassenfoss Stephen
Published: January 2017

Middle East Special Section

For nearly a decade, Saudi Aramco has been studying how altering the chemical makeup of seawater injected into its reservoirs can increase production. The result is an increasingly complex view of the interactions caused by the makeup of seawater that explains why seawater does more than just add pressure and help sweep the remaining oil out of a reservoir.

The goal is to cost-effectively maximize production by altering the chemistry of seawater. Hundreds of technical papers have been written on the potential benefits of reducing the salinity in seawater injected into formations.

More recently there has been a growing body of work on how other ingredients found in seawater—particularly sulfate, calcium, and magnesium—can add to oil output by freeing oil from reservoir rock.

Saudi Aramco has focused its research, dating back to 2008, on how seawater is able to increase production from carbonate reservoirs. Two recent technical papers from Saudi Aramco show that it has begun considering how it might modify its water treatment system to turn seawater into “smart water” (SPE 179564), and also offers an update on laboratory studies investigating how the active ingredients in seawater affect oil production (SPE 179590).

What is clear from those papers and other sources is that seawater, which Saudi Aramco turned to as a cheap option to scarce fresh water, can enhance the amount of oil ultimately recovered from the ground. The research also suggests that it can make seawater more effective by altering its chemical makeup, turning it into smart water. But this option is neither simple nor cheap.

Reducing the salinity of the extremely salty seawater used by Saudi Aramco would require desalination on a massive scale. Further changes to make it smart water add processing steps and may require new technology to reduce the energy required and to overcome the fact that available water treatment methods were not designed to selectively remove ingredients from water.

Turning seawater into smart water is a logical next step for the company, which has long been processing seawater on a huge scale to maintain production from its fields. Its Al-Qurayyah Sea Water Plant processes millions of barrels a day of seawater, removing small particles, microorganisms, and oxygen. Now the company has begun considering whether to add further processing steps to apply what it has learned about seawater chemistry by fine-tuning the makeup of the water.
Partnership Key to ADNOC’s Technology Qualification Initiatives
Authors: Whitfield Stephen
Published: January 2017

Middle East Special Section

As the oil price downturn continues to impact market stability, and its older reservoirs produce diminishing returns in the face of high energy demands, the Abu Dhabi National Oil Company (ADNOC) has recently focused on new technology development and qualification as a key function of its operations moving forward.

One such initiative aimed to develop ADNOC’s technological goals is a collaboration with BP to form an earth surface technology center in Abu Dhabi. And, in seeking to boost recovery from its assets and meet its production targets, the company created its own standards for qualifying new technologies, thus helping it realize strategic production targets and lower overall development costs. Based on the qualification standards of other operating companies and the US National Aeronautics and Space Administration (NASA), ADNOC’s standards on new technologies is set to deploy by the end of the year.

Earth Surface Technology Center

BP and ADNOC have collaborated on a number of joint venture projects recently, including technological initiatives. BP sends employees to Abu Dhabi to provide technical and managerial support to ADNOC and its operating companies. And last year, at the Abu Dhabi International Petroleum Exhibition and Conference (ADIPEC), the two companies announced the signing of a memorandum of understanding (MOU) for the development of a center for earth surface technology. The center aims to help improve the optimization and management of oil reservoirs and increase extraction of oil and gas from hydrocarbons in the emirate of Abu Dhabi, the largest of the seven emirates comprising UAE. The MOU was a result of technical discussions which began between the companies in 2014.

Under the terms of the MOU, BP will provide technical assistance to ADNOC for setting standards for works and products, which will be aimed at improving performance through the enhanced oil recovery technique.
India Road Tests Its E&P Growth Plan
Authors: Rassenfoss Stephen
Published: January 2017

Mike Watts is the cofounder of Magna Energy, an exploration and production (E&P) startup with no operations and a contrarian business strategy targeting Indian oil and gas.

At a recent presentation in Houston promoting India’s upcoming bid round of small field discoveries, Watts, who led Cairn Energy’s exploration program when it made big deals and discoveries in India, played up the country’s unrealized oil and gas potential.

“You need to be passionate and believe in the geology of India,” Watts told the 150 people who attended the road show publicizing the bid round. Based on his experience dating back to the 1980s, he believes India “is vastly unexplored compared to the potential.”

His vision has the backing of Carlyle Group, a private investment bank, which committed up to USD 500 million to support Magna’s program to build production and reserves in India.

The upbeat mood of the road show contrasted with the dark mood of the current global oil business. India is “a big growing market which is a bright spot in an unsettled world economy,” said Dharmendra Pradhan, India’s minister of Petroleum and Natural Gas.

The sale is an early test of Indian Prime Minister Narendra Modi’s program to expand domestic oil and gas production, which has included sweeping regulatory changes in the world’s third-largest energy-consuming country.

If the country is unable to increase its flat oil production trend line, the International Energy Agency predicts that India will be importing 90% of its oil by 2040 to meet its needs.

“India has a dependence on imported oil and gas, and a clear policy has been set in place to relieve this dependency and that presents tremendous opportunities in the E&P sector,” said Atanu Chakraborty, director general of the Directorate General of Hydrocarbons, which is running the auction of properties relinquished by the state-owned Oil and National Gas Corp. (ONGC).

Mixed Emotions

Consultants in India agree there is reason to be upbeat about India’s future, but they are feeling the global oil slump.

“The last 18 months have been very hard,” said Ashish Chitale, who runs Praesagus RTPO, the Indian partner for the consulting firm Sierra-Hamilton. “All the excitement is potential excitement.”
Drilling Improvements Work Toward the Perfect Well in the Eagle Ford
Authors: Wilson Adam
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 178897, “Drilling Improvements in Pursuit of the Perfect Well in the Eagle Ford—More Than 52% Reduction in Drilling Time and 45% in Cost in 2½ Years,” by Claudio J. Coletta, SPE, Camilo Arias, and Scott Mendenhall, SPE, Statoil, prepared for the 2016 SPE/IADC Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. The paper has not been peer reviewed.

In the Eagle Ford, an integrated approach to engineering and operations was key to optimize performance and improve understanding of the area. Application of technology and standardization of operations resulted in continuous performance improvement. Detailed planning and execution, application of rotary-steerable systems (RSSs), implementation of an optimized casing design, contractor performance management, clear and open communication within the team, and implementation of a performance incentive plan all played a part in the overall drilling-performance improvements.

Challenges

Although drilling operations were under way in the area, it was found that existing drilling practices and designs were not well-suited for this well type. At the start, there was a lack of standardization in planning, execution, and communication between office and field staff. Different rigs were performing the same operation differently. Rig moves from well to well on the same pad took exceedingly long. Well performance was challenged by complicated geosteering approaches, a conventional wellhead that required waiting on cement, low rates of penetration (ROPs) while drilling the curve and the lateral sections, and high pressure and temperature while drilling the production hole. High downhole-tool-failure rates resulted in multiple trips in the production section.
The Importance of Scale-Inhibitor Analysis - A State-of-the-Art Overview
Authors: Wilson Adam
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 179900, “The Importance of Scale-Inhibitor Analysis in Scale Management—A State-of-the-Art Overview To Provide Cost-Effective Scale Control From Simple to Complex Production Scenarios,” by Stephen Heath, SPE, Baker Hughes; Gill Ross, Shell; and Gordon Graham, SPE, and Kirsty MacKinnon, Scaled Solutions, prepared for the 2016 SPE International Oilfield Scale Conference and Exhibition, Aberdeen, 11–12 May. The paper has not been peer reviewed.

The accurate and precise analysis of scale inhibitors plays an important role in making key decisions on the efficiency of scale-squeeze and continuous-chemical-injection treatments. Numerous techniques exist for scale-inhibitor analysis, ranging from the simpler methods to more-complex techniques such as high-pressure liquid chromatography (HPLC) and mass spectroscopy (MS). This paper presents a state-of-the-art review of scale-inhibitor-analysis techniques and describes how these techniques can be used to provide cost-effective scale management.

Introduction

Inorganic-scale deposition is a major problem encountered during production of oil and gas and is often managed by the use of chemical scale inhibitors to prevent scale from forming in the system through continuous chemical injection or by periodic batch squeeze treatments. In most cases, scale prevention through chemical inhibition is the preferred method of maintaining well productivity. Scale-inhibitor squeeze treatments provide one of the more common and efficient methods for preventing the formation of carbonate and sulfate scales in the near- wellbore region, tubing, and topside facilities of production wells.

For any scale-management strategy where squeeze treatments are deployed, the objective will be to achieve the longest possible treatment lifetime to maximize oil production and minimize the number of costly well interventions, especially in complex production scenarios. In order to achieve the required longevity for squeeze treatments, it is essential to use a scale inhibitor that is fit for purpose for the proposed squeeze application (i.e., good scale-inhibition performance, nondamaging, good retention/ release properties, and readily and selectively detected to low levels in produced fluids). Indeed, the accurate and precise detection of the scale inhibitor in the produced fluids to low levels at or below the minimum inhibitor concentration (MIC) is a key factor to enable long treatment lifetimes and prevent wells from scaling.
Plume Modeling Establishes Efficacy, Safety of Gas Extraction From Lake Kivu, Rwanda
Authors: Wilson Adam
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27247, “Plume Modeling in Lake Kivu, Rwanda, for a Gas-Extraction Facility,” by Timothy L. Morse, Nicolas F. Ponchaut, and Gary N. Bigham, Exponent, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission.

Lake Kivu is unique among East African Rift lakes with high concentrations of dissolved carbon dioxide (CO2) in that it also contains methane (CH4). The dissolved gases constitute a hazard because a vertical disruption of the water could cause gas-laden water to be displaced to shallower depths with lower pressures, allowing the gas to bubble out of solution and triggering a gas eruption. A floating gas-extraction facility has been constructed to extract gas-laden water, separate the methane and some of the CO2, and reinject the degassed water, thus increasing the safety of the lake and simultaneously providing CH4.

Introduction

Lake Kivu sits along the border between the Democratic Republic of the Congo (DRC) and Rwanda, in the Great Rift Valley region of Africa. The lake is approximately 89 km long, oriented in a north/ south direction, and 48 km wide. The lake is at 1460 m above sea level and has a maximum depth of approximately 485 m in its northern basin.

Lake Kivu has an unusual thermal structure. At depths below approximately 80 m, the water temperature increases with depth. However, the water also contains large quantities of dissolved CO2 and salt, with concentrations that increase with depth. The density-increasing effects of CO2 and salt maintain the lake stratification despite the inverted temperature profile.

The density structure of the lake is a series of relatively homogeneous mixed zones separated by density-gradient layers. The major mixed zones, beginning at the surface, are referred to as the Biozone, Intermediate Zone, Potential Resource Zone, Upper Resource Zone, and Lower Resource Zone. The Main Density Gradient separates the Potential Resource Zone from the Upper Resource Zone. The Secondary Density Gradient separates the Upper and Lower Resource Zones.
Blowout Prevention and Relief-Well Planning for the Wheatstone Big-Bore Gas-Well Project
Authors: Wilson Adam
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 174890, “Blowout Prevention and Relief-Well Planning for the Wheatstone Big-Bore Gas-Well Project,” by Eric R. Upchurch, SPE, Sam Falkner, Andrew House, SPE, Chinh Nguyen, SPE, and Ken Russell, Chevron Australia, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.

The offshore Wheatstone project in Western Australia uses subsea big-bore gas wells as the preferred method of producing the field. Each of the highly productive wells represents a source of gas that, if accidently allowed to flow unhindered, could present an uncommonly difficult well-control challenge. This paper details the engineering and operational planning performed to ensure that no uncontrolled hydrocarbon releases occur during the execution of the subsea big-bore gas wells and that, if a blowout were to occur, the response to such an event would be sufficient and robust.

Introduction

The Wheatstone high-rate gas-well design, with its 9⅝-in. production conduit, represents the company’s initial attempt at implementing such a well. Because the design team’s combined engineering and execution experience included neither big-bore wells nor reservoirs of Wheatstone’s productive magnitude, well-control expectations were limited to anticipating needing only a single relief well in the event of a blowout. However, upon receipt of dynamic-kill simulations performed by consulting experts in that field, a new reality became obvious. That is, the combination of a large wellbore connected to the multidarcy Wheatstone gas reservoir has the potential to produce at more than 1 Bscf/D if flow is unconstrained; in some scenarios, this could require the use of up to four relief wells simultaneously injecting 15-lbm/gal drilling fluid to regain control.

Analyses suggest that it is improbable that a dynamic kill at Wheatstone can be performed successfully using only a single relief well, given the large diameter of the production wellbore. Therefore, the well-control risk of drilling a Wheatstone well was mitigated not by limiting its productive capacity (i.e., reducing the well diameter) but by (1) optimizing casing-setting depths to minimize the number of required relief wells, (2) designing the well to be completely pressure competent, even if it were totally filled with gas, and (3) formulating a blowout-response plan that is reflective of the complexities of executing a two-well dynamic kill on any of the nine foundation wells drilled at Wheatstone.
A METHOD FOR OPTIMIZING CHEMICAL COMPOSITION OF STEELS TO REDUCE RADICALLY THEIR ALLOY ELEMENTS AND INCREASE SERVICE LIFE OF MACHINE COMPONENTS
Authors: Kobasko Nikolai
Published: January 2017

A method for optimizing chemical composition of steel is proposed and a correlation is established to reduce cardinally alloy elements in existing steel grades that results in high compressive residual stresses at the surface of intensively quenched steel parts and increasing strength and ductility of material due to super- strengthening phenomenon. The algorithm of optimization consists in reducing alloy elements in existing alloy steel in 1.5 – 2 times and then lowering step-by-step content of steel, beginning from the most costly alloy element and ending the most cheaper one, until established correlation is satisfied. The range of reduction is minimal and during computer calculations can be chosen as 0,001wt%. The proposed approach can save alloy elements, energy, increase service life of machine components and improve environmental condition. The method is a basis for development of the new low hardenability (LH) and optimal hardenability (OH) steels.