bluuebunny/crossref_metadata_2025_split huggingface dataset:
Efforts on Technology Application to Unlock Gas Reserves in Low Permeability Reservoirs: A Lesson Learned in Semberah Field, East-Kalimantan, Indonesia
Authors: Jauhari Usman , Widiastuti Bhakti , Wijanarko Andre , Permana Robhy C 
Published: October 2012

Abstract
The Semberah field is located onshore on the Mahakam delta, East-Kalimantan, Indonesia. It is operated by VICO Indonesia. Reservoirs in this field consist of multi-layered sandstones deposited in a complex fluvio-deltaic environment. After more than 30 years of production, this field has reached a mature stage. Most of the remaining reserves are locked in low permeability reservoirs, on which conventional techniques have not been very effective in depleting the reserves.
These low-permeability reservoirs require technology innovations to economically produce the reserves. A comprehensive approach was taken by a multidisciplinary team of geologists, reservoir engineers, drilling and completion engineers to assess options for technology application and identify candidate reservoirs for low-perm zone development. Several technologies were considered including horizontal wells, radial jetting, and hydraulic fracturing. Of the technologies applied, horizontal well was proven as the most effective technique to increase productivity of these low-perm reservoirs. One horizontal well was successfully executed and intersected 867 ft of lateral section into the target reservoir. The well was put on production giving exceptional results. For comparison, the well increased the gas production rate of the target reservoir from 1 MMSCFD using conventional techniques to 15 MMSCFD using horizontal drilling. Currently, the horizontal well is still producing. Cumulative production has reached in excess of 7 BCF after a period of 6 years. Other technologies, such as radial jetting and hydraulic fracturing, were also applied but they recover moderate-size gas reserves with less successful results. Lessons-learned were captured and several elements of improvement were identified for future application.
This paper illustrates the lessons learned in searching for the fit-for-purpose technology application to unlock gas reserves in low-permeability reservoirs in a geologically complex environment such as the Semberah field.
A New Approach for Making Deep Water Marginal Fields Economical
Authors: Millheim K. K. , Rueff S. , Rosengren M. , Tygesen T. 
Published: October 2012

Abstract
There are over 3000 deep water discoveries that are deemed non-commercial because of the cost and time to develop this discoveries employing conventional deep water technology. For nearly six years a new technology has gone from extensive engineering analysis to a field test in 1000 meters of water in the Gulf of Mexico that proves that a Self Standing Riser (SSR) could be the enabling technology for another way to drill, complete, test, produce, and intervene in deep water wells, leading to a step-change in the overall economics.
The concept for using the Self Standing Riser (SSR) for deep water applications is not new. Its use to support production pipelines is proven and well documented. Also, for over two decades tension leg platforms have relied on the same physics and engineering that the SSR is based on.
The technical and economic viability of using the SSR for drilling, completion, and production was explored by a major independent E&P company. Later, another company further expanded the possible use of the SSR for intervention and well testing (Millheim et al. 2010). Deep water assets deemed non-commercial using conventional deep water technologies can be made commercially economical using the SSR to produce an early cash flow to help finance the exploitation. How this new SSR can make non-commercial deep water fields commercial is the basis of the content of this paper.
Finding Sweet Spots through Seismic Fracture Extraction - Unconventional Case Studies from Around the World
Authors: Oppermann Ralf 
Published: October 2012

Abstract
This paper presents innovative techniques & workflows in structural volume interpretation that have been developed to reliably visualize faults and fractures at extremely high resolution from 3-D seismic data, and to subsequently integrate these results with other seismic, well and mine data to derive fully calibrated and deterministic fault/fracture network volumes for resources.
Examples from Oil & Gas, Mining and Geothermal projects around the world demonstrate that these new techniques can provide a step-change in understanding drilling, production and safety issues in existing wells or mines. Furthermore, they can be utilised to optimise future resource activities and recoveries, and increase the safety of future operations.
A new Improved Resource Recovery technique has been developed that increases recovery from both conventional and unconventional reservoirs, as well as geothermal or mining resources.
A new Well & Mine Screening & Planning technique has been developed that reduces drilling & mining risks and costs and optimises well & mine placements within the resource area.
Results obtained through these techniques provide a step-change in understanding drilling and production problems in compartmentalized, fractured, unconventional and structurally complex resources, where fractures in the subsurface can form fluid barriers or fluid conduits.
Studies performed over a number of unconventional reservoirs (shale gas, tight gas/oil, fractured basements and coal seam gas) from around the world demonstrate that productive sweet spots in the subsurface can now be reliably located and directly targeted.
A focused application of the new technology workflows can deliver increased recoveries from resources. It can also result in safer, cheaper and more successful drilling and mining operations. As such, these workflows are proposed as Best Practice methods for resource development planning and execution.
Paper Title Reservoir Characteristics of Carboniferous Age Coals and Shale in the Cherokee Basin, Mid-Continent US, Results of 20 Years of Production
Authors: Tedesco Steven A. 
Published: October 2012

Abstract
The coal bed methane industry has been present in the United States since at least the 1920s. The most recent surge in activity began in the 1980s and was driven by tax credits. In the 1990s rising gas prices increased activity in both the United States and Canada. Activity peaked and is presently in a very mature stage in the mid-2000s as shale gas replaced coal bed methane.
Coalbed methane and shale gas production has been present in the Cherokee basin since the 1920s (Figure 1). The reservoirs are generally found from 80 meters to 650 meters with an average depth of 375 meters. Many wells will flow gas in a very short period of time and generally have low water production. Individual reservoirs tend to 0.6 to 1.2 meters thick and are of Desmoinesian age. Reservoir characteristics have only been defined post field development. The Cherokee basin now has 20 years of production history for over 5,000 wells which allows a more detail analysis of reservoir characteristics and what actual reserves are.
Testing and Perforating in the HPHT Deep and Ultra-Deep Water Environment
Authors: Wendler Curtis , Scott Martin 
Published: October 2012

Abstract
The US Gulf of Mexico is one of the few regions in the world where wells are completed in the deepwater Miocene and Lower Tertiary reservoirs. These deepwater plays have required constant technological improvement to equipment service capabilities in order to maintain integrity in the 30,000-psi environments and minimize risks. Although capable tools and guns have been developed, continuous assessment of reliability still remains vital in the exploratory processes.
Testing for production analysis in deep and ultra-deep water is critical, and when target reservoirs produce heavy oil, gas and condensate, or are in HP/HT environments, planning safe tests with risk mitigation that can gather high-quality data is paramount. Because of the high rig rates for deep-water operations, prolonged periods of low temperature and heat loss that can affect production or enable hydrate formation and other environmental challenges cannot be ignored. Fluid volumes and water depths can increase well-control time and expense. Also, since well tests are conducted from mobile vessels, alarm and subsea equipment philosophies are critical to success, and well-test string configurations must be flexible yet control well safety.
Obviously, all issues must be understood for the program plan to anticipate the potential challenges. The purpose of this paper is to explore these issues as well as discuss mitigation methodologies. The considerations, merits, and limitations of various solutions will be considered. Lessons learned from actual cases will compare the consequences of inadequate preparation to the benefits of proper design.
This paper explains why and how the methods and equipment suggested should be used and will include:
DP vessel testing Well integrity at extreme depths and pressures Functional pressure-operated tool windows Coiled tubing Cushion and mud-type criteria Hydrate prevention Perforating strategies.
Subsurface Appraisal and Field Development Planning of the Gas Condensate Field GVLA, Angola
Authors: Balasubramanian S. , Wang B. , Li Y. , Ginger E. P. , Liang B. , McKay D. M. , Brinkman J. J. , Ogden K. A. , Kennedy D. D. , Wilcox W. T. , Yang A. 
Published: October 2012

Abstract
The Greater Vanza Longui Area (GVLA) field is located in Area B of the offshore Cabinda, Angola Block 0 concession. GVLA is a multi field development and will target hydrocarbon resources in the Cretaceous Pinda formation that contain reservoirs with rich gas condensates and underlying volatile oil rims.
The objective of this paper is to demonstrate the rigorous subsurface evaluation process employed for developing a large offshore gas condensate field. The strength of the reservoir evaluation is the large amount of good quality appraisal data gathered and used to benchmark subsurface inputs. There have been 6 reservoir penetrations, 4 DSTs and 3 full reservoir cores and multiple fluid samples.
A structured workflow was followed to identify and incorporate the uncertainties in the subsurface assessment. Probabilistic forecasts helped to fully characterize and realistically assess the uncertainties. The uncertainties were grouped mainly into static and dynamic categories.
The impact of the static uncertainties was assessed using 3-D geological models. Geologic models were built upon a core-based sequence stratigraphic framework for the Pinda formation. The facies, petrophysical properties and top depth of reservoir were varied to capture the uncertainty ranges seen in the GVLA wells and analogue fields. These models captured the net-to-gross uncertainty which has the largest impact on hydrocarbons in-place and connectivity.
The dynamic uncertainties were assessed using statistical design of experiments. Monte Carlo simulations were employed to generate the probabilistic estimates. Reservoir simulation with the compositional formulation was used as the primary forecasting method. Robust equation-of-state models were built to appropriately quantify natural gas liquids (LPGs) which were value drivers for the project. Various development alternatives (primary depletion, gas injection) were evaluated and detailed economic analysis were performed for concept selection. The production forecasts were verified with material balance models, analogues.
Thermal Maturity Estimation of Gas Shale Layers From Conventional Well Log Data: A Case Study From Kockatea Shale and Carynginia Formation of Perth Basin, Australia
Authors: Labani Mohammad Mahdi , Rezaee Reza 
Published: October 2012

Abstract
Thermal maturity is an important parameter for commercial gas production from gas shale reservoirs if the shale has considerable organic content. There is a common idea that gas shale formations with higher potential for gas production are at higher thermal maturity status. Therefore estimating this parameter is very important for gas shale evaluation. The present study proposes an index for determining thermal maturity of the gas shale layers using the conventional well log data. To approach this objective, different conventional well logs were studied and neutron porosity, density and volumetric photoelectric adsorption were selected as the most proper inputs for defining a log derived maturity index (LMI). LMI considers the effects of thermal maturity on the mentioned well logs and applies these effects for modelling thermal maturity changes. The proposed methodology has been applied to estimate thermal maturity for Kockatea Shale and Carynginia Formation of the Northern Perth Basin, Western Australia. A total number of ninety eight geochemical data points from seven wells were used for calibrating with well log data. Although there are some limitations for LMI but generally it can give a good in-situ estimation of thermal maturity.
A Practical Guide to Unconventional Petroleum Evaluation
Authors: Russell Boyd , Freeborn Randy , Keinick Wayne 
Published: October 2012

Abstract
The advent of unconventional petroleum resources has radically altered the landscape when it comes to project development. Most of the traditional methods to predict reserves are no longer useful. This paper will review the traditional evaluation practices and recommend improvements.
Forecasting conventional oil and gas reserves has traditionally been done using Arps equations that were designed for Boundary Dominated Flow (BDF), but unconventional wells may experience transient flow for up to a decade or more before the onset of BDF. Arps requires the combination of a super-hyperbolic period that smoothly transitions to an exponential tail to model this unconventional behavior. Unfortunately, the Arps equations offer no information as to when this transition occurs. A new class of empirical decline equations, termed stretched exponentials, is gaining favor in forecasting shale oil or gas. These equations are beneficial because an exponential period is not required. This paper will review the three most popular methods and compare them to Arps. Other decline issues covered include: how much data is necessary to provide a reliable forecast, and how to efficiently forecast hundreds or thousands of wells.
When building type wells, it can be challenging to obtain statistically valid and significantly similar wells. For instance, fracture size, fracture fluid type, completion technique, well location and many other factors may need to be considered in order to obtain meaningful groups. This paper will suggest possible groupings and propose methods to confirm their validity.
This paper will also demonstrate that type wells created with only historical data, as is standard practice, are logically flawed. When historical production data is merged with reliable production forecasts to build a type well, the resulting type well is the best available representation of the underlying data. A detailed review and analysis of the type well equations plus real-world examples will demonstrate this point.
Integrated Formation Evaluation for Cretaceous Carbonate Khasib II of AD Oilfield, Iraq
Authors: Zhao Limin , Liu He , Guo Rui , Feng Mingsheng , Zhang Zhaowu , Zhang Yaowen , Wang Jun 
Published: October 2012

Abstract
AD oilfield is located in the southeast of Iraq and structurally it is a long axis gentle anticline in Mesoptamian foredeep. This oilfield is in the development planning stage. The accurate formation evaluation plays an important role in making development strategy. In this paper, integrated evaluations of major target formation, Cretaceous carbonate Khasib II were introduced with the combinations of available data.
Khasib II was mainly deposited within marine carbonate platform shoals and distributed stably in the full field with an average thickness of 40m. Based on the core data, four rock types are defined. Upwards lithology varies from planktonic foram micritc wackestone through green algae packstone to bioclastic and calcarenite grainstone. The porosities are almost same, about 25% while permeability varies in a large range for different lithology. Lower Khasib II planktonic foram limestone has no more than 1mD in permeability and no higher than 1ohm.m in resistivity while Upper Khasib II limestones have 10mD in average permeability and high resistivity. Reservoir spaces are mainly pores and vugs while fractures are not developed. Pore types are mainly intragranular pores, intergranular pores and intercrystal pores. Two throat types, the tubular throat and the lamellar throat are identified which are the major control factors for leading to the difference of permeability in lower and upper Khasib II. Test results show that lower planktonic foram limestone is dry and upper limestones produce oil which can be inferred that the low resistivity for lower Khasib II is resulted from the lithology rather than water. Reservoir distribution, petrophysical properties and fluid distribution for upper Khasib II are analyzed.
Shale Reservoirs: Improved Production from Stimulation of Sweet Spots
Authors: Hashmy Khaled H. , Tonner David , Abueita Samir , Jonkers Jos 
Published: October 2012

Abstract
In the quest to increase reservoir contact, horizontal drilling and multi-stage hydraulic fracturing is the common theme in the stimulation of productive shale reservoirs. Twenty to thirty stage fracs are not uncommon in some of these reservoirs. Cost, and sometimes safety considerations, can lead operators to make do with minimal information in the laterals. The selection of frac intervals is often guided by measurements in the pilot hole and stages are placed more or less evenly along the lateral. Field examples presented here highlight the fact that comprehensive LWD or openhole wireline data, acquired with the special deployment techniques in the lateral, clearly demarcate the good zones (sweet spots) from intervals with inferior reservoir characteristics. LWD Spectral GR has proved its worth in this regard and an innovative acoustic LWD measurement has provided valuable data in the laterals that has aided stimulation design.
An original approach involving real time monitoring of hydrocarbon (C1 – C8, benzene, toluene) and non-hydrocarbon gases (CO2, N2) dissolved in the drilling fluid in the mud stream has proven successful in independently identifying sweet spots in the laterals. On the other hand, near real time measurements of XRF, XRD and pyrolisis measurements on drill cuttings at the wellsite have clearly established their worth in identifying zones suitable for stimulation.
Field examples presented here demonstrate how these techniques have been successfully used to identify sweet spots and have thus helped enhance the effectiveness of hydraulic fracturing, resulting in improved production from shale reservoirs. Production data are presented to show how productivity is enhanced by concentrating on sweet spots.
When Control Line Fails, What is the Alternative?: West Malaysia Experience
Authors: Razak M. Abdul , Pate B. A. , Ismail Z. , Ibrahim M. 
Published: October 2012

Abstract
Angsi X06L was a firm candidate for a workover targeted to be re-completed in April 2010. This well was diagnosed with a severe downhole control line leak, causing the well to be shut in and led to Angsi field deferment of 800 barrels oil per day. PETRONAS Carigali Sdn Bhd (PCSB) had already attempted to rectify this problem by injecting pressure activated sealant a few times but failed in its efforts. Based on the diagnostic done, the leak rate was more than 1.5L/min, way beyond the selected activated sealant capability. The next possible option was to install a storm choke or ambient valve but unfortunately this method was prohibited by PETRONAS. Late April 2009, PCSB embarked on a technical feasibility study using high strength duplex alloy to permanently replace current surface control sub-surface safety valve's (SCSSV) control line. A complex operation that involves multiple services was designed and executed which comprised permanent abandonment of the old hydraulic control line, SCSSV flapper locked open and many more multifarious steps. With the use of this new innovative application, savings of about USD 7 million from the procurement cost of well completion, rig, barge and associated services was realized. This paper will discuss project background, technical feasibility study, work designs, jobs execution and lessons learnt for such an operation in West Malaysia.
Energy Policy Using System Dynamics
Authors: Blaskovich Frank 
Published: October 2012

Abstract
Sound energy policy requires an understanding of the inter-relationships among oil and gas operations, energy costs and prices, government fees and regulation, infrastructure aging and other factors. Using system dynamics tools, we have developed a computer model to explore policy issues from the viewpoints of governmental agencies and energy producers. All interested parties are included as model actors that are driven by their interests (e.g., profitability) and are affected by the success or failure of hydrocarbon production activities and government policies. We also determine the variables that have the greatest impact on all parties and use the model to help identify the best strategies to employ in the light of uncertainties.
The model can be run as a scenario generator to find the best solutions or as a flight management simulator for training.
This makes our approach very useful to government agencies, energy companies or both groups working together.
Model results are reported showing significantly better solutions to energy policy problems than traditional linear systems or those that only focus on one aspect of the total problem (e.g., reservoir simulation, project economics, etc.). The interplay among various system components can reveal solutions that would not be found otherwise. Our approach is not about finding a unique solution, but understanding the problem and important trends. Each problem is unique.
The system dynamics methodology has rarely been used to study and understand the behaviour of petroleum energy systems. Therefore, our approach represents a new paradigm compared to more traditional techniques that typically focus on individual system components. We are interested in how production related issues affect economics and vice versa. Our model enables us to rapidly study more complex, inter-connected systems than have otherwise been reported in the petroleum literature.