bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cased Hole Formation Testing in Very Challenging Operational Conditions Reveals Mystery of Reservoir - A Case Study in South China Sea
Authors: Huang Ying Shi , You Hong Qing , Zhou XiaoPing , Guitarte Jeremias , Xian Chenggang , Liu Weimin , Chen Xiang , Guo Hongzhi 
Published: March 2015

Abstract
This paper presents how cased-hole formation testing technology solves the mystery of fluids distribution in a reservoir in a South China Sea well with very challenging operational conditions. Two wireline cased-hole formation testers were deployed together on more than 7000 m of drilpipe, which would be one of the world's longest such operations in a highly deviated well. The significant oil column that was identified results in a completely new picture of the field.
The L#4 through L#8 formations of the Wenchang Group in A-fieldwere originally believed to be gas pay. But the big question whether this belief was correct was suddenly raised when oil was identified in a deeper zone right beneath L#8 by a mini-drillstem test (DST) conducted in an appraisal and development well looking for gas. Because the L#4-L#8 formations were already cased, a cased hole formation tester was identified as the best approach to characterize the vertical fluid distribution across the column and acquire pressure measurements and PVT samples from each zone. But the operational conditions are extremely tough: more than 7000 m of pipe-assisted operation required in a highly deviated well, zero tool failure tolerance due to the time-consuming and costly long pipe-conveyance operation offshore, and thermal expansion of this long drillpipe in a nonhomogeneously distributed high-temperature profile along the wellbore could potentially jeopardize the formation tester operation.
Careful planning, smooth operation, and real-time technical support ensured flawless execution of the cased-hole formation testing. Oil instead of gas was identified from three sands to make a big oil column that exceeded everyone's expectations. Well testing showed #,#00 bbl/day of oil production with a restricted choke. More significantly, this breakthrough discovery has opened a brand new exploration and development area and has a significant impact on field development planning. This paper gives a detailed description of how this great success was achieved and a summary of technical findings from petrophysics and reservoir engineering points of view. Distinguishing features of the oil properties have been observed, which has triggered a deeper investigation of the regional petroleum system, PVT behaviors, and production and development optimization. The preliminary results of these investigations are also discussed.
Combined Energy Recovery from Coal Seam Gas Reservoirs and Geothermal Resources (Simulation Study)
Authors: Salmachi Alireza , Haghighi Manouchehr , Dixon David William , Hart Peter James , Jachmann Ashley Michael 
Published: March 2015

Abstract
Gas production from Australian Coal Seam Gas (CSG) reservoirs can be coupled by hot dry rocks (HDR) or wet geothermal resources. This study investigates the feasibility of heating the coal seams by application of available geothermal resources. Hot water or steam from geothermal resources can be circulated along a coal seam to increase the reservoir temperature. Since methane desorption from coal matrix is an endothermic process, coal adsorption affinity reduces significantly at the elevated temperatures. Therefore, when coal seam is heated, thermal equilibrium of coal is disturbed and consequently the pressure at which gas desorption starts increases. This pressure increase results in shortening of dewatering stage and also higher gas recovery from CSG reservoirs.
A simulation study is carried out on Tiffany field, San Juan Basin, US, as a well developed CSG case to investigate the effect of temperature on gas recovery. Tiffany field is located in Southern Colorado, with very low permeability of 5 mD. The simulation has been examined at a constant abandonment pressure with varying reservoir temperature. Langmuir properties of the coal at higher temperatures are estimated from the reservoir temperature by Arrhenius equation. Primary gas recovery factor in absence of thermal treatment is calculated to be 28.6%. When the reservoir temperature is increased by 38 degrees of Celsius, the total gas recovery factor is raised to 44.8% showing 16.2% gain. This temperature increase reduces the dewatering time from 180 days to only 8 days. Simulation results suggest that temperature increase by 38 degrees of Celsius can extend the life of the coal seam gas reservoir for approximately 10 more years. In addition, total water production was reduced by 14%.
Carbon Dioxide Sequestration in Dolomite Rock
Authors: Mohamed Ibrahim Mohamed , He Jia , Nasr-El-Din Hisham A. 
Published: March 2015

Abstract
Carbon dioxide sequestration in deep saline aquifers is being considered as one of the more important geological sequestration types due to the potentially large storage capacity when compared to some other geological sequestration reservoirs. CO2 will react with formation rock when injected in dolomite formations, due to the rock dissolution and precipitation of reaction products permeability may be changed. Several parameters affect these interactions including pressure, temperature, brine composition, CO2 injection rate, and overall injection scheme.
This paper addresses the effect of the temperature, injection rate, brine composition, and injection scheme on the damage generated in the formation due to CO2 injection. A core flood study was conducted using dolomite cores. CO2 was injected under supercritical conditions at a pressure of 1,300 psi, and at temperatures ranging from 70 to 200°F, and injection rates of 2.0, 3.5 and 5.0 cm3/min. Core effluent samples were collected and the concentrations of calcium and magnesium ions were measured. Core permeabilities were measured before and after the experiment to evaluate the damage generated.
The results show that temperature, injection flow rate, and injection scheme don't have a clear impact on the core permeability, the main factor that affect the change in core permeability is the initial core permeability. The damage is mainly due to calcium carbonate precipitation, and the precipitation of the reaction products between silicate minerals that present naturally with dolomite and CO2.

Introduction
Dolomite rock is carbonate rock that contains more than 50 wt% dolomite mineral (CaMg (CO3)2), calcite mineral (CaCO3) and anhydrite from the remaining percent, non-carbonate phases may also present (Warren 2000). Dolomite formations are usually heterogeneous, different kind of permeability and porosity can be identified in the dolomite includes: intercrystal,vug,moldic,intracrystal,fracture, andintraparticle porosity (Mathis and Sears 1984). Reduction of well injectivity ranged between 40% and 50% is usually noted during WAG CO2 injection in dolomite formations (Grigg and Svec 2003).
Mitigating Compaction Damage in Real-Time for Openhole Sand Control Applications
Authors: Earles Denise M. , Samuelson Marc , Stoesz Carl W. , Surveyor Nilufer Darius , Pearce Jeremiah Glen , DeJongh Hans 
Published: March 2015

Abstract
Subsurface stresses can cause formation faults, slippage, and reservoir compaction, which can damage or permanently shut in a well. Traditional means of detecting these failures are limited and usually require moving a costly rig onto locations, and then interrupting production to re-enter the well. This results in late detection of issues and allows limited counteractive options.
A new Real Time Monitoring Compaction (RTCM) system has been developed to actively monitor strain and temperature of wells. The system consists of three key enabling technologies: A fiber optic support device deployed at the sand face, a cost effective high-flow liner system that protects the instrumentation in openhole applications, and two optical wet connects for up to 12 channels.
The fiber optic support device provides a means of holding a helically-wrapped optic fiber rigidly in place at the sand face. This new technology can be installed over traditional sand screens in gravel pack or frac pack applications, with no negative impact on the sand control functionality of the screens, or the quality of the pack. The installed fiber optic provides the equivalent of a strain gauge positioned every centimeter along the length of the producing zone.
For openhole applications, a high-flow liner system was developed to protect the fiber optic support device, and the control lines. This system includes a special quick connect that simplifies the on-rig assembly and allows torque transmission in an openhole deployment.
Two 6-channel optical wet connects are the final key to this system, allowing a total of 12 connected channels. This game changing technology provides an information conduit between the fiber optic at the sand face and operators at the surface.
The same wet connect can also be used to connect more traditional means of measurements such as pressure-temperature gauges, or distributive temperature sensing (DTS).
The information relayed through this system allows the operator to infer flow and detect subsidence or compaction of the sand face before the well is compromised, allowing time to plan and execute mitigative actions. This paper will discuss the design, testing, and potential applications of this new system.

Introduction
The production of hydrocarbons can often cause a decrease in porosity of the rock formation containing them. This phenomenon is known as compaction. Wells can sustain significant damage as the formation layers shift or move along formation boundaries as a result compaction. Fig. 1 illustrates this type of shift caused by compaction. The wellbore on the left of Fig. 1 illustrates the original location of the well, and the wellbore on the right illustrates the same well after compaction (Earles 2010).
Adding Value to a Mature Gas Field by Re-analysing and Integrating Old and New Dynamic Data - Immortelle Gas Field, Trinidad and Tobago
Authors: Roopa Iannie Vashti 
Published: March 2015

Abstract
The Immortelle gas and condensate field is located in the Columbus Basin,35- 40 miles off the southeast coast of Trinidad in water depths of 235 feet. It is comprised of highly faulted stacked reservoir units. The TP88 reservoir unit, the subject of this paper, was discovered to be gas bearing in 1975 by the exploration well, SEG10.The reservoir pressure is 3505 psi;with a temperature of 162F.This reservoir was developed with two wells. IA11 was the first producer from 1999 to 2002 and was completed as a 3.5 (inches) multizonal completion across 3 reservoir units, but selectively producing via sliding sleeves. IA14 is the second and current producer. It was completed updip to IA11 in the TP88 in 2001 as a cased hole completion with a gravel pack completion in the good quality upper sand lobes with 3.5 (inches) tubing.
The TP88 reservoir has historically had close alignment between static and dynamic models. Pressure Transient Analysis and modelling studies in 2010 has resulted in significant misalignment of the static GIIP and the estimated dynamic GIIP. This paper will describe the modelling work flow and discuss the key lessons learnt from analysing and integrating old and new reservoir data that has led to a completely different understanding of the drive mechanism and future reservoir performance. This has resulted in the static model Gas Initially In Place (GIIP) now lagging behind the reservoir simulation model GIIP and has potential implications for the reservoir depletion plan.
A New Approach for Gas Fields Development within Uncertain Business Context
Authors: Marchini Roberto , Calvarano Maria , Cocchi Giacomo , Botta Marco 
Published: March 2015

Abstract
This Paper analyses a new approach for the development of Non Associated Gas (NAG) and the recovery of Associated Gas (AG), within an uncertain business context.
The new gas fields' development approach is intended to be applied in Nigeria and other developing countries where the business context can be affected by several constraints, such as: funding availability, projects approval delay, flaring down policies, gas profiles uncertainty at project approval time, local content laws and lower profitability than oil projects.
The new approach is based on: reverse design based on service rather then gas profile, design replication, "building block development", standard procurement, competitive design.
The realization of a standard station for treatment and compression of gas (characterized by modularity, compactness, easy transport and installation and use of standard components) has been proposed and preliminarily analysed.
This paper describes the implementation of "first installation" of Standard Compression Station (SCS) within a wider gas master plan, the analysis of peculiarities of the development concept and the opportunity to share this new approach with other business areas.
In general, the Gas Supply Agreements are based on flat plateau, "constant" for a long period; therefore the gas development plan should not be based on the peak of production but on the sustainability of regular gas volumes to accomplish the required profile during the years.
The idea is to define the "functionality" of Standard Compression Station that will be installed on existing flow-stations, without interferences and with minor modifications, recovering gas presently flared (in agreement with the flaring down policy) and allowing the development of NAG fields in surrounding areas. The replication of Standard Compression Stations (distributed in a wider area) can opportunely sustain the gas supply commitment to users (typically power stations and LNG plants).
In case of several installations, the major expected advantages are: design replication, potential cost saving from replicable Contract strategies and framework agreements, time to market reduction, simplified construction, installation, and commissioning activities, maintenance synergies security costs and, furthermore, more constant expenditure.
The installation of Standard Compression Stations represents a benfit for the environment when the gas associated with the oil production can be recovered. In light of this there are opportunities that can be exploited to apply for Carbon Credits, in line with the Kyoto Protocol.

Background
Nigerian context is characterized by on shore block maturity from the oil side with a declining oil fields production, so the current plants with minor maintenance expenditure can be kept operational for the following years. Oil and gas field are distributed in a wide area with several logistic difficulties (due to security difficulties, absence of fast connections, swamp).
Integrated Structural Modeling & Seismic Attributes Analysis for Fractured Basement Reservoir Identification in Pangea Block, South Sumatera Basin, Indonesia
Authors: Budiman Agung , Priyono Awali , Samodra Ari , Mu&apos;in Fatkhul , Latuconsina Musalam 
Published: March 2015

Abstract
The development of basement structures in Pangea Block (PB) had a complex geological history related to poly-phase deformation of South Sumatera Basin. The application of conventional seismic method for naturally fractures distribution mapping could not be conducted directly due to dimension of fracture that below the seismic resolution (sub-seismic). This paper presents integrated G & G methodology for fractures mapping in basement using structural model and seismic attributes analysis. Result of the study was expected to provide input for further oil and gas field development, particularly on basement rocks interval.

Introduction
Pangea Block (PB) is located in South Palembang Sub-Basin which represents southern edge of South Sumatera Basin. Hydrocarbon bearing reservoirs in fractured basement rocks surround of this block were first discovered fortuitous by Pertamina in 1988 at ASD-1 well drilling (± 15 km southeastward out of PB) (Sardjito et al, 1991). The main issue for fractured basement mapping in PB is not only related to polyphase deformation history that involved complex basement lithology, but also the limited of conventional seismic method due to fracture dimension that below the seismic resolution (sub-seismic). Therefore, the authors applied structural model and FMI analysis as the constraints to control the seismic attributes features.

Geologic Setting
Geodinamically, basement geometry of this basin controlled by the three episodes of regional deformation, as follow : complex accreted of continental fragments during Mesozoic, collision of India-Asia in Late Eocene, and subduction of Indian ocean plate beneath Eurasian continental plate during Early Tertiary to Recent time. The compressional event in Mesozoic responsible for basement heterogenities form in PB. Several well record and petrographic analysis show it consists of granite, granodiorite, syenite, and andesite. They were overlied respectively by Tertiary sediment of Lahat Formation (LAF), Talang Akar Formation (TAF), Baturaja Formation (BRF), Gumai Formation (GUF), Air Benakat Formation (ABF), Muara Enim Formation (MEF) and Kasai Formation (KAF). Impactogen effect of India and Asia collision during Late Eocene believed as a trigger of South Sumatera rifting that forms half graben system in PB, then increasing movement of oblique subduction along the western offshore of Sumatera since Middle Miocene had been affected basement involved compression and reactivated the old structures became inversion (reverse) and wrench fault in Plio-Pleistocene.
Self Standing Riser Offers Alternative to Conventional Deep Water Approach for Developing Marginal Deep Water Oil and Gas Resources
Authors: Millheim Keith K. , Aune Geir 
Published: March 2015

Abstract
In water depths greater than 150 meters hundreds of oil and gas discoveries have been made and deemed non-commercial for one reason or another. Many of these fields are in concessions or leases without any hope of near term development because the conventional approach for developing an offshore field requiring a MODU, subsea completions, and some type of floating production system is cost prohibitive. Also, many of the current concession holders without deep water experience feel deep water technology is too complex and risky to venture into without a super-major or major independent with deep water experience as their operating partner. Also, geophysical technology has delineated hundreds of high probability deep water oil and gas leads that will not be drilled because the indicated field sizes are too small. Yet the history of basin development clearly shows most of the big fields are found first and are few. Most of the further discoveries follow a log normal distribution where size of the field reduces but the frequency of the smaller fields increases. The challenge is how to make these marginal deep water oil and gas fields commercial.
This paper presents the Self Standing Riser (SSR) technology as an enabling technology which could be the solution for commercializing non-economic deep water oil and gas fields. This paper describes the SSR and how it can enable lower cost drilling, achieve faster first oil, lower the required capital that is necessary to commission a project, and how the early production can be used to provide capital to complete the project.
A field test of an SSR in 1000 meters of water for nearly four and a half years is cited as well as the next steps to use the SSR for a marginal field development (see Figure 1 showing the buoyancy device after 2 years). How the SSR provides a new way for intervention in deep water using coiled tubing, and the possibility for developing deep water heavy oil and other applications also will be discussed.
Mounds and Boundstone Facies in the Late Carboniferous Early Permian Pha Nok Khao Formation-equivalent of the Loei Syncline, Loei-Phetchabun Foldbelt: Implications for Reservoir Quality
Authors: George Annette , Lazar Shahar , Booth John 
Published: March 2015

Abstract
Late Carboniferous-Middle Permian carbonate platforms are major petroleum reservoirs in the Khorat region of northeastern Thailand. Previous sedimentological work on these platforms in outcrop and core highlighted the dominance of platform interior (subtidal to intertidal) facies and platform margin (shoal) facies, with minor boundstone facies typically associated with the platform interior (e.g. phylloid algal mounds). Reservoir quality reflects depositional and diagenetic controls on porosity and permeability development, notably dissolution of skeletal components and dolomitisation of platform-margin bioclastic facies, and/or faulting and fracturing associated with post-depositional (Triassic and younger) collisional tectonics.
An outcrop analog study of the Pha Nok Khao-equivalent platform in the Loei Syncline (northern part of the Loei-Phetchabun Foldbelt, LPF) shows that diverse platform-margin boundstones were locally developed. Three features of the study are highlighted:sandy shoal facies include diverse encrusting organisms (such as Tubiphytes) suggest local binding and stabilisation;phylloid algal mounds, including large mounds up to 10 m high and 30 m long grew in outer platform to upper slope settings and are associated with off-mound grainstones-rudstones that also contain clotted fabrics and in situ growths of calcimicrobes and/or calcareous algae; andcalcimicrobes are a notable component in boundstones and other features such as abundant peloids in phylloid algal mounds also attest to microbial activity.
The importance of boundstone/reefal facies as reservoirs is well known in Permian basins worldwide and recognition of more widespread boundstone facies in the LPF has important implications for the distribution and quality of reservoir facies in ongoing production in nearby fields and an active exploration program. A potential subsurface analogue may be recorded in the Dong Mun Field. The distribution of bound fabrics/mounds is consistent with the distribution of 'clean' skeletal facies and both indicate that higher energy oceanographic conditions prevailed along the western and northern/northwestern margins of the platform (modern-day orientation). Large mounds with stylolite-associated porosity and adjacent microbialite/grainstone facies represent an alternative exploration target to dolomitised grainstone-packstone facies with vuggy and intercrystalline porosity.