bluuebunny/crossref_metadata_2025 huggingface dataset:
Perturbation of Homogeneous Thermal Conductivity Distribution in Some Carbonates by Stylolites
Authors: Padmanabhan Eswaran
Published: March 2015

Stylolites are partings within rocks that exhibit complex mutual column and socket interdigitization. These features can exhibit pronounced roughness on several scales. Stylolites, under deep-burial conditions, could permit circulation of undersaturated fluids and become reservoirs allowing also deep commercial gas production. However, the impact of stylolites on variations in thermal conductivity in carbonates is not well-known. This study was undertaken to investigate the heterogeneity in thermal conductivity in a variety of carbonate specimens containing different types of stylolites.

A total of 9 carbonate samples from Turki were used in this study. These sampes were imported into Malaysia by a local factory. The stylolites were classified into three types. Type 1 (sharp-peak) has well defined and high density (4 amplitudes per cm) fractures. Type 2 (simple wave-like) is intermediate whereas type 3 (sutured) has poorly defined and low density (< 1 amplitude per cm) fractures. The thermal conductivity of type 2 (mean = 3.30 W m-1K-1) was the highest and that of type 3 (mean = 1.35 W m-1K-1) was lowest. Similar trends were recorded for non-stylolitic faces of the three carbonates specimens mentioned above. Faces with stylolites showed a high degree of variability in terms of thermal conductivity when estimated at various points. Surfaces with stylolites tend to show different thermal conductivity values than non-stylolitic faces. The reduction in porosity, type of stylolite and a possible effect of different orientation of the carbonate minerals in the stylolites, appears to perturb the homogeneous distribution of thermal conductivity in these carbonates.

The study indicates that thermal conductivity estimation is point-dependant. The perturbations created by the stylolites would result in spatial variations in thermal conductivity with possible implications of differences in thermal maturation of hydrocarbon resources at the micro-site levels.
A Reservoir Management Tool for an Omani Fractured Carbonate Reservoir _ A Case Study
Authors: Al-sinani Ibrahim Said , Al Maamari Rashid Salim , Al-wadhahi Majid Ahmed , Paino Wan Faisal
Published: March 2015

This paper presents a case study of developing a reservoir management tool (a water coning correlation) to monitor the oil rim thickness and position in a giant densely fractured carbonate reservoir in Northern Oman. The production mechanism in the field is Gas Oil Gravity Drainage (GOGD), with crestal gas injection to maintain the reservoir pressure and dedicated aquifer pump off wells to control the oil rim position.

As the field is produced from a thin oil rim in the fractures network primarily through open-hole horizontal wells, it is crucial to keep the oil rim fixed and at such depth and thickness so that coning and cusping of water and gas into the oil producing wells is minimal.

In this study, two approaches; analytical and numerical were used to develop a correlation between produced water rate and distance of the measured Fracture Oil Water Contact (FOWC) from the well perforations. From the numerical simulation model, a correlation between the water rate produced from a horizontal well in a fractured reservoir and the distance between the FOWC and the well perforations was developed. The developed correlation from the simulation model couldn't be correlated with measured contacts data due to the improper fracture connectivity between the observation wells and the oil producers. However, a reasonable match was obtained between the fluid contacts from the developed correlation and the estimated contacts using the measured gas and water pressure data. The developed correlation could be further improved by incorporating the fine fracture details around the well in the simulation model.

This correlation could be used on a monthly basis to estimate the location of FOWC nearby the oil producer from the tested water rate. This will yield a better oil rim management by monitoring the rim position and thickness regularly and therefore produce the field at optimum oil rate. This correlation will also minimize the need for direct measurements of the contacts using the gradiomanometer surveys and hence reduce the operational cost.

Introduction

Reservoir management becomes an important and challenging aspect in mature highly fractured oil field reservoirs. One of the main challenges in the management of dual permeable (fractured) reservoirs is water coning through the fractures. This issue becomes more serious in carbonate reservoirs (long open fractures) with strong aquifer support.
Development and Performance of an Eco-Friendly Cross-Linked Polymer System for Water Shut-Off Technique
Authors: Sengupta Baisali , Sharma Virender Parkash , Udayabhanu G.
Published: March 2015

Excessive water production is a serious issue to be dealt with during oil production from reservoirs. The use of gel as the water shutoff agent has been widely reported in enhanced oil recovery (EOR) for the development of mature oil fields. Polymer gels are used successfully in many reservoirs all over the world, but the problem lies in finding the suitable and economical polymer for the harsh reservoir conditions of high temperatures and salinity. The organically cross-linked polymer systems are being widely used due to their greater thermal stability and their applicability over wide pH range.

Many organically cross-linked polymer gels have been developed till date but most of them suffered setbacks due to their inefficacy at high temperature and salinity, carcinogenicity or non eco-friendliness. In the present work an eco-friendly organically cross-linked polymer system of Hydroquinone (HQ)/Hexamethylene tetramine (HMTA) cross-linked polyacrylamide (PAM) has been developed which is suitable for water shut-off.

The gel formed by cross-linking HQ and HMTA with PAM is found to have high mechanical strength, form gels at high temperature of about 120°C and retain stability for long periods of time. The performance of this system has been studied both by bulk gelation as well as in-situ gelation techniques. The gelation temperature was varied from 85°C to almost 120°C to study the variations in the performance of the polymer system. The in-situ gelation study was carried out by means of sandpack core flooding.

The present gel system is very efficient in water shut-off technique and can be applied in oil fields without much damage to the environment as both HMTA and HQ are ecofriendly with HQ being harmful to aquatic life to some extent. The performance and efficiency of this polymer system in an oil field has been judged from core flooding experiments.
Successful CTU Catenary and Well Test Operation on BY Drilling Platform
Authors: Sapian Mohd Reduan , Nordin Muhammad Helmi , Sharief Saeed Mohamed , Budi Setiawan Trigunadi , Khalid Mohd Zaidan
Published: March 2015

Field BY Coiled Tubing (CTU) Operation comprised of 2 wells to be cleaned out and perforated that are A1 and A4. These two wells target reservoir was untapped and has good potential of increasing gas production rate from BY Field.

Well A1 is an infill well while A4 is a workover well, which both operations were commenced in October 2009 using a jack up drilling rig. Problem started when these wells experienced held up as there was solid restriction inside the liner, which prevented further movement of the wireline tool and as such, perforation can't take place. After considering the escalating daily spread cost, in February 2010, decision was made to release the rig and temporarily suspend the wells for future well intervention.

Few options were available for the intervention job. After assessing all risks, the drilling team has decided to deploy CTU operation with Catenary system. This operation was considered unique and the first for Drilling Departrment. The challenge was high for the inexperienced team in handling the CTU Catenary operation. With shear determination and commitment, the drilling team managed to deliver the operation, where both wells were successfully cleaned out, perforated and flowed exceeding the minimum target.

This paper discusses the challenges faced by the drilling team in carrying out the CTU operation and lessons learnt throughout the operation.

Introduction

Upon suspension of well A1 and A4, the drilling team has started to look for solution to carry out the intervention job. Factors like cost, rig availability, effectiveness and offshore/weather condition played important roles in making the decision.

Based on detail technical discussion, the team had decided to use Rig-less CTU Catenary system. Instead of rig, a workboat was required to support the operation. It allowed Catenary system equipments (Coiled tubing Reel, Catenary System Power Pack, and Coil Feeder) to be positioned on a workboat and at the same time provided space for temporary storage of other major equipment such as tank and silos for clean-up fluids storage. Other major equipment were CTU Power Pack, Control Cabin, Injector Head stack up and flying Gooseneck were positioned on platform deck. Besides that, the platform was loaded with Well Testing equipment to control the flow by choke manifold and disposal of return from the wells by flaring through Burner Boom. On the other hand, a Slick line and Wire line equipments were placed on the platform deck for the purpose of tubing clearance check and perforation operation respectively. Using a workboat essentially saved the overall project cost because the daily charter rate for a workboat package including one support vessel is a quarter of a standard jack up rig daily cost.
Nam Con Son Basin Analysis: The Old and New
Authors: Meyer Kevin E.
Published: March 2015

Recent drilling results and activity has created a renewed interest in the Nam Con Son basin in Southern offshore Vietnam. This renewed interest follows several phases of exploration in the Nam Con Son Basin in which initial drilling and data collection allowed for the definition of a tectonic and stratigraphic definition of the Nam Con Son Basin. Incorporating the existing tectonostratigraphic interpretation with data acquired since the initial drilling campaign in the Nam Con Son Basin, Talisman Vietnam has successfully entered into the Nam Con Son Basin (NCSB). Successful integration of existing literature, tectonic models, detailed mapping, stratigraphic analysis, paleogeography and basin modeling have been used to develop an updated view of the petroleum system in the NCSB. This examination of the NCSB petroleum system presents a more complete history of the basin and therefore, a better understanding of the evolution and subsequent hydrocarbon potential.

Previous workers like Matthews (1997), Hutcheson (1989), and several other authors have been instrumental in outlining the basin history and tectonic development of the NCSB. For the purposes of this paper we will use the same naming conventions developed by Matthews (1997) in order to create some continuity between previous authors and any new interpretations. By using seismic data and a range of geologic information, key basin elements have been updated and in some cases, models challenging previously accepted ideas will be proposed for the NCSB. Regional seismic mapping and a clear understanding of the relationship between tectonics, accommodation space and sedimentation rates on a regional scale have changed our view of paleogeography and added details to the regional source and reservoir distribution models. These workflows and new ideas have allowed for the identification of areas of interest in the deepwater that will be drilled in the near future to test both old and new ideas in the NCSB.

Basin Fill Definition

The NCSB can be subdivided into four major tectono-stratigraphic units or megasequences; although other authors have further subdivided the stratigraphy, for the purposes of this paper, we discuss only these four major units. These megasequences have been subdivided primarily through an understanding of the effects of tectonics and relative sea-level on sedimentation patterns over time. The dominant mechanism, whether tectonics or sea-level, controlling basin fill over time remains unchanged within individual megasequences. This definition and subdivision plays a crucial role in understanding the various components of the basin and aids in developing predictive models for basin analysis in areas that lack significant data. The overall balance between tectonics and relative sea-level combined with other concepts like sedimentation rates, accommodation space and differential compaction are the basis for the introduction of additional granularity within the NCSB.
IPTT vs. Well Testing and Deconvolution Applications for the Thinly Bedded Reservoirs: Case Studies from the Gulf of Thailand
Authors: Kiatpadungkul Wiriya , Daungkaew Saifon , Chokthanyawat Suchart , Promkhot Soontorn , Ayan Cosan , Houtzager Johan Frederik , Platt Christopher J. , Storer Alexander James , Tabmanee Piyatad , Panyarporn Pantaporn , Voradejviseskrai Suttapan , Limniyakul Theeranun , Last Nick
Published: March 2015

In Asia Pacific region, there are many thinly bedded reservoirs which are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds. These reservoir sand bodies range from millimeters to tens of meters in thickness. Though the reservoirs are highly permeable, reservoir heterogeneity caused by silt and clay laminations affect recovery and sweep efficiency.

The typical way to test such formations is to use full scale well testing, even for relatively thin zones. In the Gulf of Thailand (GoT), a Tubing Stem Test (TST) is widely used to test each individual zone for reservoir parameters. During a TST, quartz gauges are run on wireline and the selected zone is perforated. While wireline Formation Testers (FT) have also been increasingly used in the GoT for measuring formation pressure, mobility and collecting reservoir fluids, more advanced FT tools, e.g. dual packers and Downhole Fluid Analyzers (DFA) were recently introduced to test each zone to help defining reservoir characteristics in more detail. A single probe FT deployed for pretests and fluid sampling can be used to obtain transient data during the shut-in periods after sampling in relatively thin zones. The data from these Interval Pressure Transient Tests (IPTTs) can be used to interpret reservoir parameters such as vertical to horizontal permeability ratio and horizontal permeability.

This paper discusses the uses of such smaller scale pressure transient data (single probe, dual packer formation testers) and full scale well testing using a simulation model and actual field data from the GoT. First, a single well simulation model is used to investigate the effects of thinly bedded shales at different scales on pressure transient data. The actual field data were then analyzed to obtain reservoir parameters and compared with core and PVT lab results. This paper also investigates the use of deconvolution applied to pressure transient tests of different scales to understand the effect of reservoir parameters using simulated and field data.

Introduction

Thinly Bedded Reservoirs in the Gulf of Thailand

In the Tertiary Basins of the Gulf of Thailand and Northern Malay Basin, thinly bedded hydrocarbon sandstone reservoirs have been encountered in several geological settings. In the northern Gulf of Thailand, Kra Basin, subaqueous lacustrine fan delta sandstones of between 1 to 4 feet have developed as a result of episodic deposition. In the Southern part of the Pattani Basin adjacent to the Narathiwat High, thinly bedded reservoirs of less than 1 to 7 ft were deposited in marginal marine, tidally influence estuarine channel fills settings and also in more proximal fluvial crevasse splay deposits.
S1 Asset Integrity Model and Management System (AIMS)
Authors: Sri-amorntham Apisak , Chinpongpan Roungwit , Chansakran Anan
Published: March 2015

[Abstract]

Sirikit oilfield; a better known as S1, has steadfastly delivered petroleum products to serve its country for 28 years. With its dedication towards corporate vision fulfillment, a target in 2010s decade which challenges this matured S1 asset is to maintain production of 20,000 BBLD through operation excellence and holistic sustainability.

AIMS has been realized and become a key tool in achieving its goal. The prime objective of S1 AIMS is to ensure that S1's internal resources including people, systems, processes, and plants are adequately deployed whilst performing intended functions without abusively utilized. Most of them have to be assured due fit for their purposes over their entire lifecycle in order to efficiently and effectively deliver production at minimum of 20,000 BBLD net crude until at least 2020 where risks associated with accident, safety and environmental aspects as well as loss of production are practicably kept at minimum while stakeholder values are also sustainably maintained.

Unlike other asset integrity concepts S1 foresees the importance of external factors associated with its asset integrity. The concession area covers 4 provinces. More than 400 wells are located near the villages. The asset is cognizant of community values through its kind citizenship and neighborliness where sustainable growth of asset and community becomes mutually inseparable. In addition, some external resources including authorities, contractors, and service providers are regarded as non negligible factors which also hold influenced over S1 integrity.

This paper outlines how S1 develop an asset integrity model for their matured oilfield in a holistic approach underlying with their experiences passed to following generations. They take both internal and external factors into this model. The paper aims to show how this oilfield implements their AIMS as a bridge to attain their vision. Various components in AIMS have been built. S1 AIMS has been implemented to correspond to such the conceptual model. Several actual cases are demonstrated with lessons learned and the way forwards. Some pilot initiatives which are widely accepted as good practices for other projects to follow and further development to be corporate standards and practices.
Petroleum System Analysis Using Geochemical Studies, Isotope and 1D Basin Modeling in Hendijan Oil Field, SW Iran
Authors: Hassanzade Ghanbar , Kobraei Mehdi , Ahanjan Asghar , Bagheri Tirtashi Rahim , Rashidi Mehrab , Khaleghi Mehdi
Published: March 2015

Hendijan oil field is located in north of Persian Gulf and is producing oil from 3 different reservoirs. Geochemical studies of candidate source rocks have revealed that four interval of source rocks exist in this region that could generate hydrocarbons. These formations include: Pabdeh (Tertiary), Kazhdumi (Albian), Garau (L. Certaceous) and Sargelu (M. Jurrasic).

Oil-Source rock correlations are based chemical properties, biomarkers, C13 Isotope and other geochemical indices. Geochemical analyses done in Hendijan oil field have shown that Kazhdumi and Garau formations are the most important source rocks in the region. Pabdeh formation is excluded from possible source rocks due to its low maturity. No geochemical analyses have done on Sargelu formation. Different geochemical analyses including GC, GC-MS and Isotope (Carbon and Sulfur) have done on 3 oil samples from Asmari (Tertiary), Sarvak (M. Cretaceous) and Nahr Umr (E. Cretaceous) reservoirs. In addition, burial and thermal history modeling was performed to determine timing of hydrocarbon generation in the candidate source rocks in studied field. Geology and sequence Stratigraphy analysis of borehole data including drill-cuttings provided fundamental constrains for burial history reconstruction. One-dimensional model of thermal evolution were derived from the burial history and calibrated with Vitrinite reflectance, thermal conductivity, surface and bottom-hole temperature measurements, as well as with paleoclimate data.

Regarding geochemical analysis on several oil samples, all the reservoirs have been charged by one source rock. Biomarkers and isotope data indicate that Kazhdumi Formation correlates best with oil samples.

In addition to geochemical analysis, 1D petroleum system modeling shows that Kazhdumi and Garau source rocks reached oil generation window in 3 and 4 MY ago respectively and both of them are still in oil generation window. But lack of Oleanane biomarker in analyzed oil samples and low TOC content of Pabdeh formation confirms no charge of reservoirs by tertiary candidate source rock (Pabdeh).
Unconventional Reservoirs Probabilistic Reserve Estimation Using Decline Curves
Authors: Minin Antonio , Guerra Laura , Colombo Ivan
Published: March 2015

The purpose of this work is to propose a methodology for Reserve Estimation in Unconventional Reservoirs, based on a set of production forecasts, generated from decline curves, that follow a probabilistic approach.

Because of these reservoirs nature, conventional Reserve Estimation methods are not capable of representing the intrinsic variability in unconventional wells behaviour.

Our goal is to provide a Reserve Estimation in terms of P10, P50 and P90 based on Decline Curves.

From a reference database we defined sets of Cumulative Distribution Functions of initial rate, decline exponent and initial decline ratio.

Sampling randomly among these CDFs with a Montecarlo approach, different "scenarios" - sets of the decline parameters - were created. Each of them generates a single decline profile.

So we got a set of decline curves, which allow us to reproduce the behaviour of an unconventional play: all the wells do not perform exactly in the same way the "average" well do, but they behave in slightly different ways, due to different play areas or different completion techniques applied.

This variability reflects in wells initial rate or curvature and decline of the production profiles, represented by the bunch of decline curves.

So it's possible to forecast an unconventional play field production with a considerable variability, taking into account the natural differences between wells in such environments.

For our analyses, we used a reference database of about 150 wells: 50 of them were used to extract decline curve parameters and distribution, and the remaining 100 were used as check data to assess the validity of the methodology.

We investigated several ways to combine the scenarios together, in order to obtain reliable range of variability of field production.

Introduction

Natural gas is stored in Gas Shale as free gas in rock pores (reference porosity) and natural fractures and as adsorbed gas on organic matter and mineral surfaces. The relation between these different storage mechanisms affects the evolution and the shape of gas production profile. Since this kind of reservoir has such low permeability (from 10-4 mD to 10-8 mD), it releases gas very slowly and time to reach (pseudo) steady state conditions is extremely long. The production mechanism by which gas is produced from a shale reservoir involves depletion of the fracture network and the matrix and desorption of the gas from kerogen. The gas in the fractures is produced immediately while the gas adsorbed onto organic matter is released as the formation pressure declines. Due to the limited storage capacity of the fractures, the initial gas rates will decline steeply as free gas in the matrix is being produced, and eventually stabilize when desorption begins to dominate production. The desorbed gas moves slowly through the shale matrix by diffusion, until it reaches a fracture so it can be collected in the wellbore.
Interpreting Geological Systems from Seismic Attributes: Reasons for Caution from the Northern Malay Basin
Authors: Barr Duncan Charles , Flynn Mark John , Ong Cheng-Sun , Dharmarajan Krishnan
Published: March 2015

Seismic attributes are routinely used to interpret depositional patterns, particularly where channel systems form the main reservoir sands. This paper presents an example of an apparently clearly imaged channel-like feature, the size of which did not match that implied by pressure transient analysis.

The anomaly in question is a relatively straight, sharp-edged, channel-like feature interpreted at a TWT depth greater than 2 seconds. An appraisal well was drilled through the feature, encountering a gas-charged sand at the interpreted level in the well. A drill-stem test (DST) was conducted, and gas was produced to surface in a sustainable manner. Based on the combination of seismic attributes and well data, the sand body was geologically interpreted to be a relatively clean, tidally reworked sand deposited in a linear incised valley, with thickness-width ratio of around 1:30. This ratio is considered narrow for the depositional setting, but is within published ranges for channel systems.

When the DST results were subjected to Pressure Transient Analysis (PTA) and dynamic modeling, the technique implied that the sand had a drainage radius several times that indicated by the seismic attribute. Subsequent re-interpretation of the seismic anomaly has led to the conclusion that the seismic attribute did not image the reservoir sand. Rather, the attribute is now thought to indicate an erosional cut through a coal bed, which by coincidence overlies a gas-filled sand.

The discrepancy between the seismic interpretation and the well test result has implications for volumetric estimates. Long-term production testing is therefore being considered in order to better-define the lateral extent of the reservoir. In the meantime, a high level of caution will be applied to the interpretation of seismic images from deeper reservoir intervals.

Introduction

Carigali Hess operates four gas fields within Block A-18 (Figure 1) of the northern Malay Basin: Cakerawala, Bumi, Suriya and Bulan. Gas pay in these fields occurs within multiple, stacked sandstone reservoirs that range in depth from less than 4,000 ft to greater than 10,000 ft subsea. A 3-D Q-Marine seismic survey was acquired in 2006, and attributes from this survey have been routinely used to successfully identify and target gas pay sands in the shallower reservoir intervals. Seismic attributes have also been used on deeper reservoir intervals in order to identify potential reservoir bodies.
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

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

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

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

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

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

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'in Fatkhul , Latuconsina Musalam
Published: March 2015

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

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.