bluuebunny/crossref_metadata_2025 huggingface dataset:
Monobore Solid Expandable Liners - Redesigning wells for a more Economical and Operational Benefit
Authors: Siddiqui Asim A. , York Patrick
Published: May 2016

Solid expandables liners have historically been viewed as contingency liners when operators encounter trouble zones, whether due to setting a conventional casing string high or covering unstable or loss of circulation zones or to improve drilling margins. In that event, the method of operation changes from drilling the well to saving it and still reaching total depth (TD) with the designed production string. At this point the expandable liner typically is run in a high-risk situation when the operator is attempting to save the well. It is more beneficial to design expandable system(s) in a hole section further up the wellbore where the liner would be run in a much lower risk environment.

Designing a monobore solid expandable liner into the casing program enables the operator to significantly reduce risks by incorporating another liner string in the well design without losing hole size. Additional benefits can be achieved as the liner requires less pressure to expand rather than running a smaller liner where expansion pressures are higher, reducing associated operational risks.

Alternatively, the monobore design can also reduce the number of casing strings run to TD by drilling smaller holes and using less mud and cement while maintaining the same size completion. This type of well construction methodology can lower the overall cost of the well and enable a smaller rig to drill a deeper hole. This methodology enables operators to use conventional high-strength casing to address high-pressure trouble zones further down hole where the expandable liner capabilities may be exceeded.

This paper will discuss operators' original basis of designs (BoD) of several application types, the redesigns to incorporate expandable monobore well systems, and the economical benefits they provide.

Introduction

Although the use of conventional solid expandable liners can result in significant conservation of hole size and "slowing" the telescoping effect of the wellbore (York 2008) as illustrated in Figure 1, some inside diameter (ID) reduction always occurs. The resulting non-API ID of the expanded liner can drive up well construction cost due to the relative scarcity of subsequent drilling equipment such as drill bits, bottomhole drilling assemblies (BHAs), and even retrievable test-treat-squeeze (RTTS) tools and packers. The use of expandable monobore liners can eliminate the need for these "odd" size equipment requirements.

Since introducing solid expandable liners in 1999 (Filippov 1999), end users have looked to expandables to not only extend casing shoes with drilling liners, but to do so without sacrificing any hole size in the process. This methodology is being implemented in several arenas and in several available sizes (York 2004, Jabs 2004, Filippov 2005). The monobore term, in reference to expandable technology, is defined as a solid expandable liner that when installed does not result in the loss of diameter of the wellbore (Figure 2).
Exploiting the Synergies by Combining Multilateral Well Intervention Techniques with Real Time Downhole Measurements Lessons Learned from Trilateral Horizontal Well Stimulation in the Partitioned Zone
Authors: Al-Rubaiyea Jamal , Attiea Adel , Al-Hadyani Fahad S. , Nugraha Ikhsan , Boonjai Pimteera , Erkol Zafer
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Multilateral wells pose a unique challenge to operators when planning for any intervention. Correctly accessing and uniformly acidizing all laterals continues to be challenging. While lack of reliable downhole data and knowledge about naturally fractured zones or poor correlation between porosity and permeability in carbonates limit the effectiveness of a stimulation treatment; sometimes the inability to access all laterals even prevents the lateral from being acidized at all. These limitations in acidizing, therefore, provide lower than expected gains.

Selective lateral access by using coiled tubing multilateral entry tools (CTMET) have provided a first step to selectively place fluids in each lateral. However, even selective lateral access cannot provide positive confirmation that treatment fluids are confined to the intended lateral. New downhole measurements with fiber optic assisted coiled tubing (FOACT) seek to mitigate some of the uncertainty that prevails in such well interventions.

This paper describes an innovative approach adopted for the stimulation of a tri-lateral open-hole carbonate oil producer in Kuwait. The distributed temperature survey (DTS) and real time downhole data obtained from FOACT was used in conjunction with the CTMET to map and access all laterals. The DTS profiles were used to track real-time temperature changes between fluid stages of a stimulation treatment. Identifying and prioritizing which lateral to stimulate first, lateral injection distribution, formation fluid invasion, diverter efficiency and changes to the injectivity profile were interpreted in real time to improve the fluid placement.

The paper describes the effect of combining MLRT (multi lateral reentry techniques) with the fiber optics technology simultaneously and the lessons learned from this innovation. This synergistic approach not only improved operational efficiency, well-site safety but also resulted in reviving production from a previously dead well in a cost effective manner for the operator. As a result, the entire approach towards multi-lateral well stimulation in Kuwait was revolutionized with renewed confidence towards achieving better results in future interventions.
Growth and Demise of Neogene Central Vietnamese Carbonate Platforms: The Effect of South China Sea-Opening and Onshore Uplift
Authors: Fyhn Michael B. , Nielsen Lars H. , Petersen Henrik I.
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Neogene carbonate platforms cover as much as 70,000 km2 of the central Vietnamese South China Sea margin. The margin is little explored, and so far, exploration has focussed on Miocene carbonates with a number of oil and gas discoveries made. Carbonate growth initiated during the Early Miocene following Eocene-Oligocene continental rifting. Early carbonate deposition took place on two regional platforms separated by a narrow depression that marks the trail of the East Vietnamese Boundary Fault Zone (EVBFZ).

West of the EVBFZ, the Tuy Hoa Carbonate Platform fringes the Vietnamese margin between Da Nang and Nha Trang. In the west, platform growth initiated during the Early Miocene and continued until Middle Miocene time when regional uplift along the Vietnamese margin led to sub-aerial exposure and karstification. Seawards from the EVBFZ, carbonate deposition similarly commenced during Early Miocene time (Burdigalian). Platform growth took place on the Qui Nhon Ridge flanking the EVBFZ and farther seawards on the Triton Ridge. From the latest Early Miocene, stepwise partial drowning resulted in platform split-up and seaward retreat of carbonate growth. Hemipelagic drapes cap drowned platforms and indicate protracted periods of sediment starvation after drowning. Continued drowning is evidenced by platforms subcropping the present seafloor at few hundred meters depth, and modern platform growth only remains on a number of seafloor cuestas around the Paracel Islands far from the Vietnamese mainland.

The onset of widespread carbonate deposition largely reflects the opening of the South China Sea. The mid-Neogene shift in carbonate deposition is interpreted as a consequence of regional uplift of central and south Indochina starting around Middle Miocene time when the Qui Nhon Carbonate Platform became sub-aerially exposed. Stressed carbonate growth resulted from increased inorganic nutrient input derived from the uplifted mainland, which promoted platform drowning farther offshore.
Seismic Amplitude Loss Compensation for Future Reservoir Characterization Studies in Peciko Field - Indonesia
Authors: Brahmantio Rangga Andyaksa , Kusuma Andi Setia , Bertini Florent , Dufour Jocelyn , Paternoster Benoit Jacques , Leclair Simon
Published: May 2016

This paper describes a post-stack methodology to compensate the amplitude loss prior to commencing further seismic reservoir characterization studies in Peciko field. The available 3D seismic data shows that the high frequency part (25–55 Hz) of the seismic signal contributes more significantly to the variability of extracted wavelet amplitude than the low frequency part (5–25 Hz) and within the high frequency part, the amplitudes of the extracted wavelets correlate positively with the RMS amplitude of seismic traces from which the wavelets have been extracted.

This analysis led to the design and testing of a two-step amplitude correction scheme based on maps of RMS amplitude derived from the low and high frequency bands. The first step consists of locating the areas where the seismic signals require correction. The second step respects the defined correction area and uses specific gain maps for the low frequency and high frequency components. These corrections were optimized and controlled under the careful scrutiny of quantitative seismic-towell ties and attribute maps.

Application of the methodology has brought significant improvements to the initial seismic dataset, e.g. better preserved amplitudes, less variability of wavelet amplitude and enhanced seismic detection. All of these advantages were successfully obtained while barely influencing the background information. However, it has been shown that the relative added-value resulting from this approach will depend on the quality of the initial dataset itself. Heavily damaged amplitudes under massive shallow gas or anomalously low velocity features will probably be insufficiently compensated. In this perspective, careful control at many well locations and the mapping of QC attributes are very important to assess the method.

In our Peciko case, the compensated cube enables refinement of the previous interpretations and optimization of the development plan. Furthermore, these results motivated the application to the existing angle sub-stacks and opened the way to pre-stack seismic inversion for a more extensive reservoir characterization. This workflow has been applied to the other 3D datasets, such as Tunu and Bekapai 3D, which suffer from similar amplitude losses phenomena associated with carbonate or coal masking and shallow gas pockets.

Introduction

Geological Context

Peciko is a giant gas field and is located offshore in water depths of 30 to 50 meters, southwards of the modern Mahakam river delta and approximately 25 km to the South - East of the East Kalimantan coastal line. Peciko was discovered in 1983 and the field's gas accumulation is 20 km long by 10 km wide. The structure is a large nose dipping to the north-west with no fault identified (Figure 1a).
Assessment of Undiscovered Conventional Oil and Gas Resources of Thailand
Authors: Schenk Christopher J.
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

The U.S. Geological Survey estimated mean volumes of 1.6 billion barrels of undiscovered conventional oil and 17 trillion cubic feet of undiscovered conventional natural gas in three geologic provinces of Thailand using a geology-based methodology. Most of the undiscovered conventional oil and gas resource is estimated to be in the offshore Thai Basin Province.

Introduction

The U.S. Geological Survey (USGS) assessed the potential for undiscovered conventional oil and gas resources within 23 geologic provinces of southeast Asia as part of the USGS World Petroleum Resources Project (Schenk and others, 2010). This report summarizes the assessment of conventional resources in three provinces of Thailand—Khorat Plateau Province, Thai Basin Province, and Thai Cenozoic Basins Province (fig. 1). Prior to the assessment, the geologic framework and petroleum systems were developed for each province based mainly on published literature, which is extensive for petroleum systems in southeast Asia (for example, Todd and others, 1997; Doust and Sumner, 2007; Hall, 2009). Assessment units (AU) were defined within each petroleum system, and each AU was quantitatively assessed for undiscovered conventional oil and nonassociated gas accumulations (table 1). Co-product ratios were used to calculate the volumes of associated gas (gas in oil fields) and natural gas liquids. Exploration and discovery history was a critical part of the methodology used to estimate sizes and numbers of undiscovered oil and gas accumulations.
Sichuan Basin Shale Gas, China: Exploring the Lower Silurian Longmaxi Shale
Authors: Hackbarth Claudia , Soo Kwong Yin , Singh Navpreet
Published: May 2016

Introduction

The Peoples Republic of China (PRC) has set ambitious targets to increase its domestic supply of clean-burning natural gas. Shale gas is one of the hottest exploration concepts in the global E&P industry, and according to press releases 2010–2011:• In 2010, the PRC Ministry of Land and Resources (MLR) set a target for the country to identify 50–80 shale gas prospects and 20–30 exploration and development blocks by 2020.• The Strategic Research Centre for Oil and Gas of MLR also set a goal to locate one trillion cubic metres of recoverable shale gas reserves, build 15–30 billion cubic metres of production capacity and produce 8–12 percent of China's natural gas from shale gas wells by 2020.• China National Petroleum Corporation (CNPC) announced a new shale gas research center. The center will focus on technology and equipment supporting shale gas exploration and development.• China and the United States announced the two nations would cooperate in several energy areas including shale gas development.• In addition to shale exploration already underway for own account, PetroChina signed an agreement for shale assessment with Royal Dutch Shell in November 2009 and Sinopec signed an agreement with Exxon Mobil in July 2011, for blocks in Sichuan Province and/or Chongqing Municipality.• In June 2011, auction tender results for four shale gas exploration blocks in Chongqing Municipality and Guizhou Province were announced. When the tender was originally announced in 2010, it was said that the successful Chinese companies would be able to form joint ventures with foreign partners to carry out the assessment if they so chose.

Shale gas exploration in China is already underway and rapidly increasing in activity level. The Sichuan Basin, one of the most prolific petroleum basins in China, is at the forefront. However, exploration and assessment of an untested shale gas play is typically lengthy and expensive. Compared to conventional oil and gas projects, shale gas projects may require a number of early wells to prove the existence and distribution of the gas, but then many more to test and optimize engineering techniques until a commercially viable combination is found. This process could be summarized into two over-arching questions: "Is there a material amount of gas?" and if yes, "Can it be produced economically?"
Geophysical Attributes to Improve the 3D Geopressures Prediction in HP/HT Environment
Authors: Cibin Patrizia , Mantovani Marco , Moglia Anna
Published: May 2016

The scope of the present work is to predict the pore pressure based on seismic attributes for an explorative well to be drilled in a complex area in terms of structural geology and pressure regimes.

Generally, the geopressures prediction is based on the correlation between seismic P-wave velocity and effective stress, but in the area under study this kind of relationship does not give reliable results. A different approach in analyzing the available data, based on an alternative methodology that uses the seismic inversion and the Vp/Vs ratio to predict a sudden increase of overpressure, is presented in this paper. Although a detailed interval velocity field was built using the Anisotropic Grid Tomography method, providing a good fit with the Vp Sonic log of a calibration well in the study area, the seismic/well velocities were not able to predict the abrupt increase of pore pressure near the Top Oligocene boundary with a single pressure regime. It was necessary to introduce two different pressure regimes above and below Top Oligocene in order to fit the measured pressure data. Even the Vs Sonic log did not show a significant deviation that could justify the pressure variations. However, when the Vp/Vs ratio was computed from Vp and Vs Sonic logs, a clear change in the trend was highlighted near the Top Oligocene boundary, partially confirming the presence of two different pressure regimes. In order to verify if these considerations could be extended to another prospect in the area, a Seismic Inversion study was performed around the proposed well location. Analyzing the Vp/Vs ratio volume resulting from the Seismic Inversion process, a similar trend was observed, confirming that an analogous behavior is present at the new location and a special attention is to be paid in the well planning and during the drilling operations.

Introduction

The knowledge of pore pressure using seismic data is useful in planning the drilling activity to control potentially dangerous abnormal pressures. Various rock physics conditions cause anomalous geopressure due to the formation fluids. Compaction disequilibrium is considered the main mechanism generating overpressures. It is activated when the sedimentation rate is so rapid that the pore fluid does not have the chance to 'escape' from the pore space. This phenomenon is often present during the very fast burial of shale layers, which have no time to expel the bounded water; with the increase of depth and temperature, the trapped water reaches pressure much higher in respect to the hydrostatic pressure, which may cause problems during the drilling activities. This is particularly critical in the explorative phases, when few geological and geophysical information are available and, generally, very sparse or no correlation wells are present. In these explorative areas, the seismic data are extensively used also to predict geopressures.
Advancements in Openhole Completion Technology - Establishing and Sustaining Differentiating Sand Control Completion Performance
Authors: Barry Mike D. , Hecker Michael Thomas , Yeh Charles S. , Moffett Tracy
Published: May 2016

Openhole completions are often selected as the preferred completion technique to maximize reservoir flow potential and provide reliable, high capacity, low skin completions. In many environments, these completions will also require some form of sand control. To meet development objectives, operators are continually challenged to select, design, and install fit-for-purpose completion strategies to optimize ultimate recovery for these fields. These challenges necessitated the creation of new practices, procedures, and hardware to ensure consistent delivery of reliable wellbores, across the entire organization, to achieve long-term, economic success.

ExxonMobil embarked on a multi-year initiative to establish and sustain a disciplined, systematic approach to sand control completion design, job execution, and performance assessment. The effort included the development, qualification, and deployment of selective, enabling completion technologies. Additionally, comprehensive engineering and operational guidelines, as well as, in-depth training were delivered to the worldwide engineering and operations workforce. Most significantly, the initiative is now resulting in effective and rapid transfer of learnings and best practices across the global organization. This comprehensive effort continues to focus on ensuring the right people are deploying the right technology in the right well.

This paper will discuss the guiding principles associated with our overall completion practices. It will also describe a number of enabling technologies pioneered by ExxonMobil including:• NAFPacSM, a gravel pack technique that allows the operator to run the gravel pack screens in non-aqueous fluid, gravel pack the well and displace the casing to brine, all in one trip• MazeFlo™, a self healing, redundant sand screen• Internal Shunt Alternate Path Technology (ISAPT) screens with openhole shunted packers, a completion technique that enables true and selective zonal isolation in openhole gravel pack applications

Introduction

Over the last 15 years, our industry has dramatically changed. The contrasts are remarkable. Just 15 years ago:• "Deepwater" was anything over 400 feet, not 4,000 feet• A high volume well made 3,000 bopd, not 30,000 bopd.• Completion intervals were hundreds of feet, not thousands.

Unquestionably, the development demands today are far more challenging than ever before. Wells are less accessible, have much higher drilling and completion costs and are more complicated to construct. Since fields are typically being developed with fewer wells, the overall productivity and longevity expectations of each and every completion can far exceed anything experienced in the past. As such, the ability to identify and capture the best completion practices and processes and then apply them systematically is a key step in maximizing resource value
Crosswell Seismic and Electromagnetics: New Advances in Interwell Imaging
Authors: Nalonnil Ajay , Zhang Ping , Marion Bruce P. , Phillips John G. , Dogra Sanjeev
Published: May 2016

Crosswell imaging as a concept and measurement technique for the oilfield has been maturing over the past two decades. As part of this development, both the seismic and electromagnetic versions of the measurement have seen recent advances that have allowed the technologies to answer more complex imaging requirements in the industry today. This paper features case studies which focus on the areas in which the methods have advanced, specifically; downhole seismic source, frequency attenuation tomography and indicator probability imaging.

Introduction

Crosswell Seismic Imaging

Crosswell seismic images the interwell space with an improved vertical resolution of up to 5–10 times higher than surface seismic data. Both direct and reflected wavefields are processed to provide a detailed image of the reservoir. By using higher frequency sources that are deployed alongside the reservoir interval, crosswell seismic surveying generates high vertical resolution reflection images with resolution on the order of 1–3 m. This is due to the high bandwidth of the transmitters used during acquisition with upper frequencies ranging from 800Hz to 2 kHz (depending on the transmitter used and imaging objective).

Since seismic velocity is very sensitive to pressure, temperature and saturation changes caused by the injection of CO2, gas, and steam, crosswell seismic provides valuable information for monitoring injection performance and efficiency as well as reservoir characterization. Crosswell seismic can reliably detect compressional wave velocity changes as small as 1–3%. (Lazaratos et al., 1997) Additionally, since the migrated reflection section provides a high-resolution image of the structure between wells, it helps in answering key questions about the geologic causes of the observed injection performance and fluid flow.

Crosswell Electromagnetics

Crosswell EM is a natural extension of the single well induction logging method whereby the transmitter and receiver are located in separate wells. This geometry provides high-resolution resistivity distribution of the subsurface between the wells. When obtained at different time steps during injection and production this resistivity distribution provides valuable information that can be integrated with other data to interpret the changes in the reservoir rock and fluid distribution between the wells. These data are valuable in updating the reservoir model with reduced uncertainty and enhanced predictability.

Resistivity is especially responsive to changes in fluid constitution in the reservoir and early work (Wilt et al., 1998) shows that it is also an excellent indicator of temperature related changes in the reservoir.
The Influence of Reservoir Rock Wettability on CO2-Foam Stability in Porous Media
Authors: Rafati Roozbeh , Hamidi Hossein
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

CO2 injection to produce more crude oil from the underground hydrocarbon reservoirs is one of the best methods to prevent the entry of this greenhouse gas into the atmosphere. Although the low viscosity and density of the gas create a viscous fingering and gravity override problems and reduce volumetric sweep efficiency of this process.

One of the most common methods to overcome these problems is the injection of stable aqueous foam as a mobility control agent into the underground reservoirs. Stability and strength of this kind of foam in porous media plays an important role in enhancement of the process efficiency.

Many published papers have been focused on the effects of both rock and fluid properties as key parameters of foam stability but research on the effects of critical parameters such as wettability of the porous medium, pore size and geometry remains incomplete.

In this study, foam stability was measured and compared in strongly water-wet, strongly oil-wet and mixed wet systems by using two-dimensional modified glass models. Alpha olefin sulfonate and Triton-100 were used as an anionic and nonionic foaming agent, respectively. The experimental results indicated that both foaming system presented higher stability in strongly oil-wet porous media than in strongly water-wet. It also illustrated that anionic surfactants have higher stability and mobility control performance in all water wet, oil wet and mixed wet systems.

Eventually, the experimental results showed that pore size and capillary forces are inversely related to foam stability in porous media. On the other hand, by reducing pore size, the capillary pressure increases and thus foam stability decreases inside the hydrocarbon reservoirs.
Development of Economical Gas-tight Casing Connection for Low Pressure Gas Field Application
Authors: Wang Jiandong , Yang Lineng , Song Shengyin , Yi Xiaoming , Li Dongfeng , Zhang Wei
Published: May 2016

Changqing Sulige gas field in China covers a large area of low pressure (reservoir pressure of less than 35 MPa) and low permeability reservoir. It was noted that the production rate per well has been low. Therefore, to increase the production efficiency, it was necessary to increase the number of wells to be drilled. As a result, casing connections became a large portion of the total cost of the field development. A low cost gas-tight casing connection would help to reduce the development cost in Sulige gas field. Primarily due to high cost, premium connections with dedicated shoulder and seal do not satisfy the economical development requirement. API long round threaded casing connections do not allow breakout after makeup with special thread compound (Catts101). Therefore, it is necessary to develop an economical casing connection with fast makeup feature and large bending and tensile load carrying capacity. Based on the finite element analysis, to improve the gas-tight seal performance with the API long round thread connection and buttress connection, a new type of casing connection was developed. The new casing connection has modified radii of the crest and root of the thread with wider ridge than groove to ensure full contact of the load flank and stab flank of the internal and external threads upon makeup. In addition, the thread crest and root are separate to prevent galling. The internal thread on the box has varying taper at the makeup location to enable gas-tight seal upon makeup with the last thread on the pin. Nonlinear finite element analysis of this new connection design (139.7×9.17mm N80) showed the new design with a clearance of crest and root with surface coating on box at the engaged gas-tight seal position, combined with the make-up and tensile load carrying capacity of 80% material yield, can meet low pressure (60 MPa) gas seal. This new casing connection design was verified with full-scale testing to ensure the successful application in Sulige gas field. Contrary to other premium connections, this new casing connection has no dedicated seal and shoulder regions and relies on the last thread for sealing. Such design has several advantages, such as low cost, low material consumption, easy for QC, no requirement for special thread compound and easy for make-break. It satisfies the requirement of economical development of low pressure and low permeable gas field.
Sequence Stratigraphic Interpretation of the Cretaceous through Miocene Section, Barcoo Sub-basin, Browse Basin, Northwest Shelf, Australia
Authors: Laitrakull Kasira , Weimer Paul , Bouroullec Renaud
Published: May 2016

The Browse Basin is one of four major sedimentary basins along the Northwest Shelf of Australia; large portions remain largely unexplored. The study area is located in the Barcoo sub-basin, which was a major depocenter of the Browse Basin. The sequence stratigraphic framework for Cretaceous through middle Miocene strata was developed to evaluate the stratigraphic trap potential of the basin. Analysis was based on the interpretation of 11,800 km of 2D seismic and log data from four exploration wells. Six second-order mega-sequences were recognized (145.5-112.0, 112.0-89.3, 89.3-65.5, 65.5-23.0, 23.0-19.0 and 19.0-14.2 Ma). Each mega-sequence was further subdivided into two to seven third-order depositional sequences; each of these sequences was defined and summarized with structural, isochron, seismic facies, and geologic facies analyses.

The Base Cretaceous through top Turonian strata were dominated by a major progradational-aggradational siliciclastic margin, with up to 40 km of progradation to the northwest. The sediments changed regionally, from the southeast to northwest, from coastal plain environments to shallow marine environment to the slope and base-of-slope. Potential reservoir sands are present in delta front, lower- through shoreface, fluvial mouth bars, as well as onlapping deepwater deposits and isolated channel-levee systems within the slope setting.

A major transgression occurred during the Late Cretaceous and the margin backstepped considerably. The Cenozoic section also prograded to the northwest, but is considerably thinner than the underlying Cretaceous strata, and is less prospective due to shallow burial, and lack of traps. To date, no fields have been discovered or developed within the study area. However, at least 18 leads in the deepwater Cretaceous strata were identified for further evaluation.
A Methodology of Well Abandoning in Offshore Field
Authors: Marbun Bonar Tua Halomoan , Cahyoniarso Bambang , Sinaga S.Z. , Kurnia H.A.
Published: May 2016

Every living creature has their very own life cycle: born, growth, and death. These are also applied to all oil, gas, and geothermal wells. Starting from the drilling of the well, the production of the reservoir fluids, and finally the plugging and the abandonment of the well.

During the life cycle, wells will eventually encounter problems. These problems might be caused by many aspects including cement problems, wrong casing setting depth selection, compaction, and formation subsidence and this has happened to one of the wells at the X field, Indonesia.

The X field is located in Indonesia. The TVD of well Y in field X is Y7 ft SS with a mud line depth of 89 ft. The A1 formation which is located above the pay zone has experienced subsidence caused by the production process. This event has severely damaged the cement, casing, and tubing in contact. Following the damaged cements, the casings are also damaged causing the gas leakage from the A1 formation to the surface. This problem has made the company aware of the risks involved if the production of the formation continues.

The solution recommended for the company is plug and abandon using squeeze cementing and cement plug. Leaking casings will be repaired by using squeeze cementing. The cement used for the abandoning practice will be expanding cement which has been added with pure MgO or CaO.

Introduction

It all starts from geologist finding anticlines or any other potential traps for hydrocarbon to accumulate. Seismic tests are conducted on each potential discovery. Exploration drilling will eventually be done after that to certain depths to compromise the existence of any potential hydrocarbon zones. Logging, coring, well testing and all other test were done to gather data for simulation studies. When reservoir engineers compromise that the well is profitable to produce then development wells are drilled and mass production starts.

Producing a well involves depleting the pressure inside the pores (exceptions for wells with EOR) of the producing zones. This means every second of this process will eventually shorten the age of the well waiting for problems to occur. These problems could involve sand, casing damage, or cement cracking. Many other problems involve stresses that are exposed to the cement jobs during the production phase. By time these cement jobs will eventually crack and collapse and will eventually be remediated using secondary cementing that will cost the company lots of money to continue on with their operations.

Cement problems are caused by many aspects from the drilling phase to the production phase. One of the main problems is subsidence of the formation underneath the platform. This will result in cement cracking, casing failure, and after that tubing buckling. The cracking of the cement is one the major concerns in oil and gas industry.
Reducing Gas Flaring by Improving Turndown Ratio of Centrifugal Compressor
Authors: Al-Azmi Falah Mutiaz , Parikh Chirag Ashwinkumar
Published: May 2016

The Oil and Gas Gathering and Processing facilities at West Kuwait field of Kuwait Oil Compnay operates turbine driven multistage (LP/HP) centrifugal compressor for transportation of produced gas. The main challenge for these facilities is to operate it at lower production capacities at many instaces due to various reasons. The crude oil processing units of these facilities were able to operate smoothly for as low as 25% of design capacity. However, the turn down ratio for gas compressors was limited to 55%. This limitation was resulting in offloading of compressor and subsequent gas flaring when facility was operated at lower production rates.

The main reason for compressor offload was availability of single Anti-surge control valve & control system to prevent surge and also to control capacity. This was limiting the lower operating range of compressor. The non-availability of required High Pressure or Low Pressure Gas was resulting in frequent opening of Anti-surge valve which was offloading HP stage of compressor. A modification was done to install a recycle valve in parallel to Anti-surge valve. Moreover, a control system was also modified for independent control of compressor capacity. This has significantly increased the turndown ratio of compressor.

This paper shares a field experience of limitation of compressor operating range without dedicated recycle valve for capacity control and provides guideline for designing and installing independent recycle control system for capacity control to increase lower operating range of centrifugal compressor. It was observed that actual turndown ratio of compressor improved from 55%to 20% after installing an independent recycle valve for capacity control. This improvement has increased capability to operate Gathering Centre at lower production rates without gas flaring.

The paper justifies need for installation of a dedicated recycle valve for capacity control in parallel to Anti surge valve to increase turndown ratio of multistage centrifugal compressor.
Flow Unit Characterization aided by Quantified Secondary Porosity Result from High Resolution LWD Images in Heterogeneous Carbonate Reservoir; A Novel Approach
Authors: Bahukhandi Yogesh , Kar Somenath , Majumdar Chandan , Roy Dipanka Behari , Bhatt U.C.
Published: May 2016

Heera field is one of the most prolific fields in the Mumbai offshore basin in India. The field belongs to one of the six tectonic blocks (Heera-Panna-Basseinn block) of Mumbai offshore basin. Carbonates are by far the major contributor in terms of hydrocarbon production in this field. Presence of Vugs, Fractures and Solution enhanced features makes it a real challenging job to understand the porosity distribution within this reservoir. Characterizing and quantifying the complex secondary porosity profile and identifying different flow unit is immensely important for production optimization and appropriate completion design. The challenge of understanding the porosity heterogeneity of Carbonate reservoir further increases where critical borehole condition averts the possibility of running high resolution Wireline imaging tool.

A novel approach has been taken for the first time in this field to quantify and characterize the secondary porosity distribution and permeability prediction from high resolution LWD Resistivity Image. Good quality LWD Resistivity Image has been processed using advance processing software and a quantified result of secondary porosity spectrum was obtained using robust algorithm. This quantified secondary porosity result is further utilized to characterize the different high resolution flow unit throughout the borehole.

This paper illustrates a case study where quantified result of secondary porosity and estimated permeability has been derived using LWD resistivity image in conjunction with the openhole measurements. Micro-facies variation in terms of fluid flow characterization, size & nature of vugs and laminated beds has been established. This will lead to accurate completion designing for production optimization. The result was then validated with the secondary porosity derived from the high resolution Wireline Image and Mobility data from samplingtool.

In a nutshell, this work opens a new regime of application of LWD image in terms of advance Geological and Petrophysical interpretation in addition to its other benefits like borehole stability and Geosteering capability.
Design a Model for Natural Gas Value Chain with Creative Industry Cluster with Market Viewpoint
Authors: Mousaei Ahmad
Published: May 2016

Oil and gas value chain is included exploration (seismic survey, exploratory wells, logging, and data interpretation), extraction (drilling wells (productive / dry)), production (well completion and treatment and processing), transportation (pipelines, LNG carriers, CNG carriers), storage (reservoirs, aquifers, salt caverns), distribution (distribution through local distribution companies to end users), and marketing (physical and financial trading and retailing).

At this paper, a model was developed for value chain of natural gas. This model based on market viewpoint for creative industry cluster after distribution stage. It was included two groups, one of them is direct consumption as a fuel (e.g. CNG, GTL, LNG, DME, NG (city gas), and power gas) and the other one is indirect consumptions such as methane (ammonia and methanol clusters), ethane (ethylene cluster), propane (propylene cluster), butane (butane and butadiene clusters), sulfur, and condensed (naphtha (benzene and toluene clusters)).

Introduction

A business or industry cluster, as popularized by Michael Porter can take multiple forms depending on the depth and complexity, but majority clusters include: companies of a ready product or service of one industry or aligned industries, suppliers, financial institutions3. Such clusters affect competition among businesses in three ways: by increasing productivity of the companies in the cluster, by driving innovation in the field and by stimulating businesses in the field4. A cluster thus is a grouping of institutions/firms in a geographic proximity that leads to positive impact on the economy of the cluster and their growth. [1]

During the last decades, the underlying concept of value chain was subject to different influences and objectives. The origin of value chain analysis is discussed from two distinct traditions: the French 'filière concept' and Wallerstein's concept of a commodity chain. From both, a couple of derivatives have emerged. Well known is Porter's concept of the value chain, Gereffi's global commodity chain, and Humphrey's world economic triangle, whereas the last two were joined to the concept of the global value chain. [2]

Industrial Clusters

Clusters are groups of inter-related industries that drive wealth creation in a region, primarily through export of goods and services. The use of clusters as a descriptive tool for regional economic relationships provides a richer, more meaningful representation of local industry drivers and regional dynamics than do traditional methods. An industry cluster is different from the classic definition of industry sectors because it represents the entire value chain of a broadly defined industry from suppliers to end products, including supporting services and specialized infrastructure. Cluster industries are geographically concentrated and inter-connected by the flow of goods and services, which is stronger than the flow linking them to the rest of the economy. [3]
Improving Seismic Velocity Estimation Through Separation Of Seismic Diffractions And Specular Reflections
Authors: Alai Riaz , Zahir Mohd Hafizal Mad , Adnan Amar Ghaziah M. , Verschuur Eric D.J.
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

For optimized imaging and subsequent interpretation of subsurface structures, we need to estimate a velocity-depth model from seismic data records. To minimize the risk in oil and gas exploration, it is crucial to estimate the velocities very accurately, since they form the basis for generating reliable imaging results.

However if the earth's subsurface contains many complex discontinuities, the recorded data will contain a large amount of diffraction energy that may mask the accurate estimation of velocities primarily derived from specular reflections.

Several scientists have developed methodologies to separate diffraction data from specular reflections; in this paper we illustrate the successful application of the proposed method including many of its advantages in data processing, imaging and interpretation.

The separation of diffractions from specular reflections in seismic recorded data has several advantages. Although diffraction energy plays an important role in fault and fractures identification and characterization, initial data interpretation is often done on specular reflections for better understanding the mapping of subsurface structures and stratigraphy.

In the examples shown in this abstract, the main emphasis is on the improved velocity estimation on specular reflection data after diffraction energy has been suppressed. Especially in the velocity analysis phase, diffraction energy may mask the desired velocity information extracted from specular reflections. Of course, during the final imaging stage the original data is used again. Based on some data examples it will be illustrated that the suppression of diffraction energy clearly improves the velocity picking and, thereby, yields a more accurate estimation of the velocity-depth model.

The examples confirm that a systematic application of the methodology of separating seismic diffractions from the total recorded wave fields is essential and provides better control of locating faults and fractures optimally. On the other hand specular reflection imaging will be better interpretable.
Application of PSDM Imaging for Reservoir Characterisation in the Northern Malay Basin: A Case Study
Authors: Michel Loic , Flynn Mark John , Hoo Chee-Hau
Published: May 2016

Seismic imaging in the northern Malay Basin frequently suffers due to the limitations imposed on Kirchoff Time Migration by the complexities of structure, lithology, stratigraphy and fluid effects that occur in the area (Reilly et al., 2008 and Ghosh et al., 2010). A recent Pre-Stack Depth Migration (PSDM) project not only enhanced the reservoir imaging, it also enabled the production of amplitude preserved volumes that were used to improve reservoir characterisation studies for gas-pay prediction.

Reservoir characterisation studies within 4 producing gas fields of the northern Malay Basin have successfully used offset stacks and seismic inversion products Acoustic Impedance (AI) and Poisson's Ratio (PR) to target gas-pay sands for development drilling. These sands display a weak type III AVO response. One field contains less of the type III AVO sand facies and displays lower seismic contrast; in an effort to improve reservoir prediction, the multi linear analysis EMERGE process was applied to generate target logs Volume of Sand, Porosity, Gas Saturation and Pay Flag. Although more successful in identifying pay sands, data quality issues hampered results. Shallow gas effects, such as amplitude absorption and time distortion of underlying reflectors - in addition to fault shadow effects, negatively impacted the pre-stack and post-stack data and the derivative inversion and EMERGE data. Although not a complex structural or velocity environment, PSDM processing was applied to 2 of the gas fields with the greatest data quality issues and generated improved pre- and post-stack data. The EMERGE process was re-run and delivered improved target attribute cubes. Simultaneously an inversion trial was run to test potential uplift in PSDM derived AI and PR data. The PSDM derived AI was of slightly better quality than the original while the PR was clearly superior; the data quality uplift is attributed predominantly to the improved PSDM pre-stack data input. Acoustic Impedance and to a lesser extent PR form significant inputs to the EMERGE multi-attribute process and full re-inversion of the PSDM data is under consideration to use in future characterisation studies.
Modeling of Permeability Destruction Caused by Fine Scaled Lamination of Deeply Buried Aeolian Sediments.
Authors: Strobel Joachin , Fatima Titte Nurul , Sill Otto
Published: May 2016

Despite seemingly good reservoir quality as seen by routine core and log analyses, certain gas reservoirs composed of aeolian dunes from Lower Permian age at around 5000m depth show poor well test results with respect to deliverability and connected volume.

Core analysis of those reservoirs routinely shows porosity values around 10–15% and permeabilities around 100 mD. Even standard measurements of plugs at overburden condition show a reduction of permeability by only 10%. Irreducible water saturation is often reached and has values between 10 to 20%.

Samples of such lithofacies are characterized by pronounced lamination caused by strong grain size variation. Detailed oriented (directional) permeability analyses under overburden conditions focused on such laminated samples have been carried out. It shows that thin bedding/pronounced lamination causes a reduction of bed-vertical permeability by a factor of 2 at ambient but by a factor of 100 and more under overburden conditions.

Capillary pressure curves measured at overburden conditions show a strong increase in irreducible water saturation for densely laminated sections when compared to ambient conditions.

The effective permeability is therefore seen as a function of compaction, lamination count and orientation of sediment bodies in relation to the borehole.

Core data, together with relative sediment dip information from image logs was used to model and successfully predict well test results. The densely laminated sections are too fine to be observed by logging tools directly. A simple porosity threshold can be used, whereas below that threshold such a dense lamination is assumed. This threshold has to be established by calibration to core data and is not uniform. NMR data can be used to detect the high bound water signal from compacted thin laminations.

This logging method was successfully used to define the net reservoir section within a well. The exposed reservoir section was optimized by discriminating "net reservoir" based on the abundance of laminas. Incorporation of a lamination mechanism into a reservoir model yields an improved prediction.