bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimizing Fracture Stimulation in Low-Permeability Oil Reservoirs in the Ordos Basin
Authors: Liu Xinghui , Chang Yanrong , Lu Hongjun , Chen Baochun , Li Jianshan , Qi Yin , Wang Chengwang
Published: October 2012

Huge oil reserves are located in low-permeability reservoirs in the Ordos basin in China. These reservoirs have three key characteristics: low reservoir quality (10 to 13% in porosity), low reservoir permeability (0.3 to 2.0 md), and low reservoir pressures (pressure gradients of 0.0075 to 0.009 MPa/m). Fracture stimulation is essential for commercial production in these reservoirs. To better understand fracture growth behavior and to optimize treatment designs, microseismic monitoring and fracture modeling were performed for pilot wells in key areas. In some low-permeability oil reservoirs in the basin, fracture closure stress sometimes could not be obtained from commonly used pump-in/shut-in tests because pressure decline is extremely slow. Closure stress is one of the important parameters for fracture modeling. To obtain closure stress in these reservoirs, conventional pump-in/flow-back (PIFB) tests were modified and employed. Once the closure stress in the payzone was determined, the closure stresses in adjacent and/or bounding layers were estimated from sonic log and lithology data. Fracture modeling analysis was then conducted using a calibrated fracture model, which must match both the observed net fracture pressures and the fracture dimensions from microseismic mapping. This approach led to significant improvements in fracture treatment designs in these tight-oil reservoirs. The first improvement was to maximize effective fracture lengths in fracture designs. A novel staging technique was also developed to stimulate large pay intervals using a stress diversion technique without mechanical isolation. Larger treatments using a hybrid fracturing technique were recently implemented to stimulate ultralow-permeability oil reservoirs. Production results using the new stimulation techniques were significantly better than traditional techniques in the region. This paper discusses how an integrated, engineered approach was applied to stimulate tight-oil reservoirs in the Ordos basin and demonstrates the benefits of an integrated approach to developing marginal, unconventional liquid hydrocarbon reservoirs.
Systematic Evaluation of Unconventional Resource Plays Using a New Play-Based Exploration Methodology
Authors: Neber Alexander , Cox Stephanie , Levy Tom , Schenk Oliver , Tessen Nicky , Wygrala Bjorn , Bryant Ian
Published: October 2012

New tools are now available to provide a rigorous and systematic play-based exploration approach to the evaluation of unconventional resources. Coupled with petroleum system modeling, this methodology offers an efficient and effective approach to identify "sweet spots" early in the life of resource plays. Petroleum system modeling can be applied to predict the type and quantity of hydrocarbon in shale formations, as well as the proportion of adsorbed gas and geomechanical properties that are important for hydraulic fracture stimulation of shale reservoirs. Maps of these properties are then converted to chance-of-success maps for hydrocarbon generation, retention, and pore volume that can be integrated with nongeological factors, such as access and drilling depth required to reach target reservoirs. These play-based maps are expressed in probability units, so simple map multiplication provides a map of the play's overall chance of success, delineating the sweet spots. A similar methodology is applicable to evaluation of coalbed methane resources.

In this paper, we illustrate this methodology using examples from shale oil and gas shale plays in North America. These include data-rich plays from the North Slope of Alaska and data-poor plays from the northeastern and southern regions of the United States, which are more representative of many Asia-Pacific basins. We show how predictions from petroleum system modeling based on sparse data provide a good match with results of subsequent development drilling and production.

Petroleum system-based assessment of resources in place, combined with an assessment of overall play risk, enables companies to make decisions on acquisition of acreage early in the life of unconventional resource plays based on the probability of them containing economically viable resources.
Evaluation of A Passive Ultrasonic Log Application for Casing Integrity Assessment: A Case Study in A South Oman Field
Authors: Aditama P. , Mirza M. , Al Saadi H. , Al Wardi A. , Aprilianto E. C. , Broughton D. , Troup D.
Published: October 2012

The paper presents evaluation of passive ultrasonic logging tool deployed using E-line to assess casing integrity in 3 oil producing wells in South of Oman. In addition a comparison is offered between the ultrasound logging technology and a more conventional well integrity test using a hoist and multi-set plug that has been utilized to date.

The ultrasonic log was run in a selection of oil producing wells, operated by beam pump. Those wells were confirmed as having well integrity issues from well surveillance data and were causing significant oil deferment (2.2% of total oil production). Those wells have a history of cementation challenges owning to heavy losses that occur within a water bearing zone located above the pay zone. This, combined with the presence of H2S and oxygenated water at this depth, has resulted in a number of corrosion related integrity issues across the field.

The logging program was originally planned inside tubing with surface pressures of 1,800 psi but it was decided to log inside casing (without tubing) because leak was more severe than predicted (1 m3/min of leak rate). In wells A and B, leak points at 630 m and 225 m were identified and respectively verified. However, another leaking interval in well A was also identified from conventional WIT using hoist. In well C, no pressure held on surface causing lack of differential across leak which resulted in identification failure on first attempt (inside tubing). On second attempt (inside casing), unclear ultrasound reading was attained but seven leak points still can be identified after several log passes. The tool can save significant hoist time and will become viable alternative.

In conclusion this paper illustrates examples of where the ultrasonic log has provided highly accurate leak detection, significant time saving and improvements in overall operating efficiency. The limits of the technology are also discussed with recommendations provided for the application of the service based on operational experience gained during the technical evaluation.
Overview of PCP Lifting Technology Development in Daqing Oilfield
Authors: Wanfu Zhou , Guochen Shi , Gang Cao , Mingyan Lu , Mingzhan Chen , Yu Hou , Yongxin Liu , Mingyi Zhang
Published: October 2012

This paper presented the development of Progressing Cavity Pump (PCP) technologies in Daqing Oilfield during the past 27 years, covering the successful experiences and lessons learned. The history of PCP lifting technology development was reviewed in the round. Several main PCP techniques were presented in detailed as well, including high efficiency and low profile PCP drivehead, hollow rotor PCP water flushing technique, PCP trouble-shooting technique, and PCP logging technique, etc.

Daqing Oilfield was the largest continental oilfield in China developed from 1960. Beam pumping units was the main artificial lift method. To date, there are more than 40,000 beam pumping wells. PCP was applied in Daqing Oilfield from 1983. In the past 27 years, the scale of PCP increased at a higher rate. Till the end of 2010, 6,000 plus PCP wells were applied in Daqing Oilfield. PCP has become the second largest artificial lift method in Daqing Oilfield.

To date, a series of PCP products have been developed covering the displacement and lift arrangement for different blocks in Daqing Oilfield. Based on the study and experiences for years, a set of completed PCP system design methodology was also created for water flooding, polymer flooding, ASP flooding and other complicated conditions. The fast improvement of PCP mainly resulted from two respects: Firstly, the quick development of PCP production techniques. The adaptability and reliability of elastomer was improved effectively and matching techniques were developed as well. Secondly, the requirement of low energy consumption and environmental protection in petroleum production policies enhanced the application of PCP technologies considerably.

This paper applied a successful case study of a novel technology developed in the mature oilfield which could be a great reference for the industry.
Methods for Measurement of Solid Particles in Hydrocarbon Flow Streams
Authors: Nabipour Amin , Evans Brian , Sarmadivaleh Mohammad , Kalli Chris
Published: October 2012

Sand production is one of the more critical issues causing delays and high costs to the petroleum production industry. To measure solid production in the hydrocarbon stream a number of sand monitors have been developed. Such monitors are installed in the flow line and are intended to provide information such as the onset of solid production or the amount of produced solids. Most sand monitors are based on the measurement of erosion due to impingement of sand particles or measuring ultrasonic signals generated by particle impacts on the pipe wall or piezoelectric elements.

Having described the principal behind available monitors in the industry, capabilities and limitation of each type is explained in Part 1. Part 2 is comprised of a literature review carried out on the techniques which have the potential to be utilised in new generations of solids monitors. The principles of such methods as well as their advantages and disadvantages for solids monitoring applications are mentioned.

In Part 3 subjects such as improving the data quality and data interpretation of current techniques, integration of available techniques into a single piece of equipment, and ranking of the most promising cases which are worthy of further investigation are discussed.
Integrated Approach to Unconventional Reservoir Characterization: Key for Understanding Hydrocarbon Production Challenges in Kerogen and Tight-Fractured Deep Carbonate Complex in Kuwait.
Authors: Acharya Mihira N. , Kabir Mir R. , Al-Ajmi Saad H. , Al-Maia Noura A. , Kumar Ashok , Pradhan San P. , Al-anzi Ealian H.
Published: October 2012

The unique Kimmeridgian-Oxfordian complex of unconventional and fractured carbonates has been tested to be prolific producer of gas, condensate and light oil in different wells discovered in various North Kuwait fields. The challenge is to characterize the complex reservoir flow system where critical reservoir parameters such as reservoir type, porosity and permeability characteristics, and production and pressure data can vary substantially.

The relationship between the natural fractures and the tight matrix in controlling effective system conductivity in reservoir flow units are the key features which dictate the nature of inflow mechanisms thus the production performance. The paper deals with developing an effective methodology which integrates the variations in critical reservoir properties of the low porosity yet naturally-fractured carbonate reservoir.

The drill stem test (DST) results in some wells were successful without stimulation, while in other wells the DSTs were unsuccessful in spite of advance and repeated stimulations, thus categorizing these plays as geologically-complex, tight gas condensate reservoirs where out of ordinary stimulation techniques may be needed to activate the fractured matrix. Pressure transient analyses and flow regime interpretation of the successfully-tested wells confirm the dual porosity flow-system and the fractured nature of the reservoir.

In this paper, the authors will discuss a new integrated approach for understanding the production and pressure behavior in light of the unique unconventional reservoir characteristics along with the fractured reservoir properties. Dual-layer and dual poro-perm models for pressure transient analysis have been applied extending the previous study of relationship developed between the productivity index (PI) and the total organic carbon (TOC). The proposed integrated methodology can significantly improve the current approach to production optimization, reservoir management strategy, completion, and stimulation design in fractured tight gas condensate reservoirs in Kuwait as well as in other regions.
Evaluation of Sand Screen Performance using a Discrete Element Model
Authors: Feng Yuqing , Choi Xavier , Wu Bailin , Wong Chong
Published: October 2012

Sand screens, including wire wrapped sand screens and slotted liners are often installed in sanding prone wellbores to control sand production. The selection of optimal sand screen aperture for a given sand body is critical to minimize sand production while maintaining well productivity. Laboratory sand retention tests were developed over 10 years ago to provide a basis for sand screen selection. Unfortunately, these experiments have a number of limitations. For example, the results can be substantially different depending on how the tests are conducted and data interpreted. This can lead to different (sometimes wrong) sand screen types and screen opening size recommendations.

This paper presents an initial investigation of the sand production problem from wire wrapped screens and slotted liners, through the use of discrete element model (DEM) for the solid flow with or without fluid flow coupling using computational fluid dynamics (CFD). The focus is on some key design and/or operating parameters affecting sand retention over the sand screen, such as the screen opening size, initial solid concentration, fluid flow velocity as well as particle shape.
Pushing the Envelope of HT Drilling Fluids: Development and Field Applications of a Novel Non-Aqueous Drilling Fluid in the Gulf of Thailand
Authors: Charnvit Kerati , Kongto Abhijart , Huadi Fransiskus , Sharma Sunil , Simon Gerard , Estes Brent , Trotter Neil
Published: October 2012

Typical wells in the Gulf of Thailand are drilled using a slim-hole design that requires 6⅛-in. hole for their reservoir interval. The slim and highly deviated well geometry, potential of high acid gas contamination, and high-temperature environment requires a well-engineered non-aqueous drilling fluid (NAF) to meet the overall well objectives. These conditions always place severe limitations on the drilling fluids design and often lead to failures in openhole wireline logging operations, which is the most important well objective.

The key fluid properties to ensure the success of wireline logging operations under this high temperature are high-temperature, high-pressure (HTHP) filtration control, filtercake quality, and thermal stability of the drilling fluid under extreme static condition. Selected emulsifier and HTHP filtration control agents work synergistically in providing excellent hole condition which allows the hole to be fully logged and evaluated. Clear benchmarks were set and monitored in all the field applications: (1) Successful wireline logging operation; (2) Variation of mud weight after static condition; (3) Variation of mud weight compared to formation tester data point.

This paper details the design, development, and field applications of an ultra-high-temperature NAF used for drilling deep and hot wells in the Gulf of Thailand. In addition, the extensive laboratory work required to optimize the formulation for extreme high temperatures, the lessons learned, and the critical engineering guidelines for running a NAF in such harsh conditions will be described.
Predicting the Arrival of an Interference Response in a Direct Communication Test
Authors: Fair Chris , Goldsberry Fred
Published: October 2012

The purpose of this paper is to provide a more relevant solution to the diffusivity equation than the conductive disc/zero potential flow (Exponential Integral) solution, especially for use in predictions of the time that is required for an interference effect to reach an observation well. After explaining the assumptions and theory behind the method, a direct integration of the radius of investigation will be presented, along with a physical explanation of what it is. While presenting multiple examples to support the theory, the results from Exponential Integral method for predicting interference arrival at an observation well will be compared. Finally, it will be demonstrated that the classic radius of investigation equation is more appropriate in interference/communication testing, and that rate, gauge resolution, and the total system pressure drop do not affect the arrival of the interference effect.
A Methodology for Reducing Bias in the Design & Evaluation of Hydraulic Fractures
Authors: Newman S. , Fair C.
Published: October 2012

The purpose of this paper is to present a framework to reduce bias in the design and evaluation of hydraulic fractures. When we mention "bias", we are referring to human nature. If someone knows what the answer is supposed to be (what someone else wants, or to provide a consensus), they are much more likely to provide that answer - even if it is not correct. In addition to frac design (and re-design after pre-frac tests), this process will be extended to the process of post-frac evaluation and the analysis of the frac flowback and other well tests. The process consists of three parts, to be done in isolation from each other. The first is the actual frac design. This includes the gathering of the geo-physical and reservoir property information, the creation of the geo-mechanical model, the selection of equipment, and the execution design to meet the operator's objectives. It also includes any re-design required based on DFIT/minifrac analysis, performed prior to the frac. The second part is the review of the fracture operation, often called the Frac Replay. This is where the actual field data (rates, pressures, concentrations, etc.) and geo-mechanical model are used to simulate the pad and proppant placement and concentration in the fractured interval. The final part is analysis of the frac flowback, as well as any subsequent well tests. If designed and executed properly, the flowback/well test data can provide an independent validation of the effective fracture length, fracture efficiency and drainage radius/volume.

The reason for performing these three parts in isolation is that it utilizes service companies, consultants and in-house experts to the operator's advantage. If they are not performed independently, the answers are highly susceptible to a forced consensus, especially if the party doing the design or performing the frac job wants to demonstrate the effectiveness of their work. If the results of all three independent parts point to the same conclusions, the operator has more confidence in the outcome. If not, the differences can be examined, with an eye to improving future designs and executions.
Renewal Plan: Efficient Strategy for Optimum Development in Mature Fields – A Success Story from Sanga-Sanga Assets, Indonesia
Authors: Wijanarko Andre , Ismanto Bambang , Permana Robhy , Pizzolante Italo
Published: October 2012

VICO Indonesia is the operator of the Sanga-Sanga Production Sharing Contract located onshore of the Mahakam delta, East Kalimantan, Indonesia since 1968. Over 40 years the PSC has produced 70% of the estimated original gas in place, supporting Bontang LNG plant. VICO has 7 producing fields, in a complex fluvial deltaic deposition with more than 2700 gas and oil reservoir, mixed of depletion and water drive mechanism reservoir. VICO production peaked at 1.5 BSCFD in 1995 then start to decline. Current production is in the range 385 MMSCFD of gas and 14500 BOPD of liquids from 400 active wells.

In a situation of 46% annual base decline, to fulfill domestic and LNG contractual commitments and to optimize reserve recovery, VICO generated and implemented an integrated and aggressive work program called "Renewal Plan". This is an integrated approach between reservoir management and technology application; it provides a detail road map to onward development strategy.

The main elements of the plan are extensive development drilling activities (conventional drilling, grid base drilling, cluster well drilling), low permeability reservoir optimization (horizontal well, hydraulic fracturing, radial drilling), production optimization (deliquification technique, permanent coil tubing gas lift for monobore type) and facilities optimization (reducing abandonment pressure by additional compression installation, wellhead compressor, debottlenecking).

Technology application in drilling, completions, production and facilities optimization combine with synergy from multidisciplinary team have resulted in maintaining VICO production decline in the range of 5% (vs 46% base decline), allowing promoting and partially replacing the reserves at an attractive development cost, even after 40 years production life.

This paper will describe the successful implementation of renewal plan in VICO Indonesia, which proved to be an efficient example of better reservoir management for optimum development of mature assets.
Formation Damage in Geothermal Wells (Salamander field case)
Authors: Bedrikovetsky P. , You Z. , Badalyan A. , Hand M. , Matthews C. , Jenson D.
Published: October 2012

A new mathematical model for flow towards the well during water production from geothermal reservoirs accounting for fines mobilization, migration and clogging of production well is developed. Treatment of the well discharge data from geothermal reservoir A (Australia) exhibits good agreement with the results of mathematical modeling, which validates the model. The sensitivity analysis based on published laboratory data and theoretical model prediction shows that geothermal reservoirs are particularly vulnerable to fines migration due to reduced electrostatic particle-grain attraction at high temperatures. The modeling shows that large flow rates result in the increased formation damage and productivity impairment.
Lessons Learned from a Water Shutoff Technique for Cross Flow between Two Perforation Intervals in Al-Khafji Field
Authors: Al-Dhafeeri Abdullah M. , Mohammed Tawakel , Moawad Taha M.
Published: October 2012

The excess of water production from oil wells in several areas of Khafji field is a subject of concern for reservoir management. Water shut-off techniques are common practices to reduce water production which is resulted in well productivity improvement. An oil producer well-A, was worked-over on February 22, 2006 to conduct a water shutoff technique on existing perforation intervals utilizing a cement squeeze. Several logs such as RST and Gamma Ray were carried out to identify the fluid movement. Then, the well was produced with an oil rate of 1,200 BOPD and a rapid increase of water cut of 60%. The well was still unstable in terms of rate due to high water cut. The well was considered for rigless work-over to control the water using Mechanical Through Tubing Bridge Plugs (MTTBP) to isolate the lower two perforation sections. After setting the Bridge Plug with 8 ft. of cement above the plug, the well was revived with production stream. During the first 24 hrs of well production, the treatment result was not as expected which resulted in 100% water cut. A discussion was made by reservoir management engineer to continue of production for additional 24 hrs. With time, the well showed a positive result with a reduction in water up to 95%. It is recommended to keep the well to be produced over 21 days with final results showed the well revived with an oil production of 1,500 BOPD with zero water cut.

The result showed a successful water shutoff technique and scenario to retrieve the well with 100% water cut produced after treatment. Challenges, intervals selection, design criteria, lessons learned, and results of the water shutoff technique will be discussed in this paper.
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

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

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

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

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

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

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

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

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

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

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

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

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.