bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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.
Economics of Gas-To-Liquid Processing (The Effect of Scaling on Profitability)
Authors: Uzoh Obinna Vincent , Bretz Robert Elvin
Published: March 2015

Previous economic studies of Gas-To-Liquids (GTL) processes have considered large scale plants for liquid production rates of 50,000 barrels of liquid per day (BLPD) (approximately the equivalent to 500 MMscf per day of gas consumption) or more. This paper is guided by the need to produce "stranded gas reserves" using small scale GTL technology. This study examined simple profitability indicators for small scale GTL plants. We made use of capital cost estimates supplied by a reputable company headquartered in Colorado, for a Fischer-Tropsch plant designed in the year 2000 with a production capacity of 50,000 BLPD.

Exponential scaling was used for estimating the capital cost for a base case unit with a production capacity of 1000 BLPD, or an equivalent typical gas consumption rate of 10 MMscf per day. A base case set of parameters was assumed and the profitability indicators of net present value (NPV) and discounted cash flow rate of return (IRR) were calculated.

A sensitivity study shown on a spider diagram was performed by varying five economic parameters; Capital Cost, Plant Capacity, Product Price, Feed Stock Price and Cost of Trucking. Each of these parameters was varied over an appropriate range while others were held constant. For each combination of parameters the NPV and IRR were calculated and a spider diagram for visualizing the sensitivity was prepared. Our calculations indicate that the profitability is most sensitive to changes in the product price.

Changes in capital costs at a given unit capacity caused the next most sensitive profitability behavior. Profitability is nearly as sensitive to the plant capacity as with the capital cost for a given capacity. Profitability is less sensitive to changes in the cost of the feed gas but over the range of possible costs, it could be a deal breaker. Profitability is least sensitive to the cost of transporting the product.

Our results indicate that under the right circumstances a relatively small GTL plant could be profitable. With success in ongoing work to develop more integrated Fischer-Tropsch (F-T) process, the capital cost could easily be reduced for such a small unit, making the economics even more profitable.
Fracture Characterization using Borehole Image Logs and Seismic Data to Define a Successful Drilling Target in the Fractured Basement - A Case Study from the Nam Con Son Basin, Southern Offshore Vietnam
Authors: Li Bingjian , Hoang Phuoc Son , Mai Binh Van , Marie lefranc
Published: March 2015

The fractured granite basement in the Nam Con Son basin of southern offshore Vietnam has become a new exploration target in recent years. However, there are two major challenges in the early days of exploration. First of all, it is not always easy to locate a drilling target, for example, a faulted zone or a better fractured area on seismic due to the often degraded data quality within basement. Secondly, it can be difficult to drill the target with better well trajectory due to often poor understanding of the potential productive fracture systems. Those two challenges are also very common for most of the fractured basement reservoirs.

In this study, available regional geology data including structural geology information and outcrops have been collected to help geoscientists to gain a basic understanding of the local geology related to the basement and fracture development. A full suite of well data from an existing wildcat well in the same block including conventional open hole logs, advanced well logs (i.e. borehole images and SonicScanner), mud logs as well as PLT (production logs) and DST data was carefully studied to extract all possible information on natural fracture and fault. This resulted in two main outputs - the fracture density log along the wellbore and the defined potential fracture/fault system with dip and strike. Then the fracture output from the existing well was used to fully calibrate the seismic attribute analysis for the whole block, which mapped out the fracture density in 3-D volume. A new exploration well with high deviation was designed on the basis of fracture density volume data as well as the understood potential productive fracture/fault attitude (dip & orientation) and drilled smoothly. A commercial hydrocarbon discovery was made in this new basin first time in the fractured basement.

Introduction

Hydrocarbon has been discovered in the Miocene and Oligocene clastics as well as carbonates in the Nam Con Son basin, southern offshore Vietnam since 1990's. However, drilling activity for the Pre-Tertiary granite basement has been still very limited without any commercial discovery until late 2010. This paper intends to summarize the fracture characterization for the studied field where the 1st commercial oil discovery in the basement was made in the Nam Con Son basin as well as the learned experience on how to define a drilling target based on the limited existing well data and seismic data in the exploration stage for this unconventional fractured tight reservoir.
Deploying Multi-Stage Completion Technology in HPHT Applications
Authors: Oberhofer Robert
Published: March 2015

Over the last several years open hole, multi-stage fracturing systems (OHMS) have proven to be an effective and efficient completion technology in many unconventional reservoirs. To date, OHMS completion technology has been limited to a maximum differential pressure of 68.9 MPa (10,000 psi) while performing the fracture stimulation treatment. As the industry targets deeper formations while drilling longer horizontal laterals, some wells now require treatment pressures higher than 68.9 MPa (10,000 psi) to perform the desired stimulation and realize the added production potential OHMS technology offers. As a result, there is a need for OHMS completion tools capable of handling very high pressure/high temperature (HPHT) conditions.

The challenge in creating HPHT completion tools is in the material requirements. Considerations must be made regarding how to ensure integrity of the seal between the liner and the annulus, the gripping capability of the packer elements, and the ability of the materials to withstand the downhole conditions. HPHT OHMS tools were designed and manufactured with improved metal alloy and premium seal technology. The basic design and function of this HPHT system is the same as the standard OHMS; therefore, the HPHT tools build on the field-proven technology.

Case study wells are presented in a recently developed, deep shale gas formation just east of the Rocky Mountains with highly overpressured downhole conditions. This, combined with a high fracture gradient, resulted in sub-optimal fracture initiation with the standard OHMS. By employing the HPHT OHMS, higher treating pressures were achieved with successful treatment results. Using this technology, several additional wells have been completed in the same geographical field and implemented in other HPHT applications.

Introduction

Over the last five years (2007 - 2011), more than 5,000 horizontal wellbores have been completed using OHMS in unconventional shales, tight sandstones and tight carbonate reservoirs in Western Canada. In addition to providing time and cost reductions, OHMS completions have realized production benefits compared to conventional completion methods because they allow contribution from natural fractures and the open hole lateral (Snyder and Seale, 2011; Edwards et al., 2010; Houston et al., 2010; Lohoefer et al., 2010; Lohoefer et al., 2010b; Samuelson et al., 2008).

OHMS fracturing method. With the advancement of horizontal drilling and completion practices in recent years, many wells are now drilled horizontally with the intention to fracture stimulate multiple intervals. A very common technique has been to complete the well with a multi-stage fracturing system that is installed on a liner in the open hole without cementing the horizontal (Seale et al., 2006; Seale, 2007) (Fig. 1).
Challenges Evaluating Shale Gas Well Performance Catalogue Fingerprint: How Do We Account for What We Don't Know?
Authors: Boulis A. , Jayakumar R. , Nyaaba C. , Rai R.
Published: March 2015

Shale gas has emerged as a viable source of clean energy with advances in horizontal drilling and multi-stage fracturing. Well performance in the ultra-low permeability shale gas is governed by the interaction between reservoir rock and the fractures created during hydraulic fracturing. Numerical modeling historically has been used to study impact of variation in reservoir properties and completion characteristics on well performance. Shale gas field development requires a large number of wells to be drilled. The inordinate resource requirement to numerically model each well, necessitates the development of quick diagnostic tools. This paper explores how readily available pressure and rate data can be utilized to estimate and understand the unknowns involved in the completion and the reservoir parameters. Synthetic models have been used to generate well performance history which was then diagnosed using an analytical modeling workflow to generate well performance signatures. The synthetic models provided a controlled basis to study the reservoir and completion phenomena which are difficult to measure in the real field data. In practical application, multiple unknowns can co-exist to impact the overall well performance

Some of the major unknowns that were studied are reservoir permeability, fracture spacing, fracture half-length, fracture and matrix permeability changes with pressure. This paper also captures the performance signature changes with variation in original gas in place (OGIP) and the impact of contribution from stimulated rock volume (SRV) and external rock volume (XRV) outside the SRV. Fracture geometry is rarely known with certainty so this paper also addresses the performance changes that can be observed for various fracture geometry realization while conserving the total fracture area in all the models. The final section of the paper will address understanding the impact on estimated ultimate recovery (EUR) forecast for a particular scenario and how error in estimating the same reduces over time. We believe this fingerprint catalogue will serve as a valuable resource for prompt identification of dominant flow mechanism while providing a diagnostic method for identifying key indicators that control overall well performance.
Analysis on the Impact of Fracturing Treatment Design and Reservoir Properties on Production from Shale Gas Reservoirs
Authors: Cohen C.E. , Abad C. , Weng X. , England K. , Phatak A. , Kresse O. , Nevvonen O. , Laffite V. , Abivin P.
Published: March 2015

Production from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design, which have improved productivity of these reservoirs. However, further advancement of treatment design requires a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and treatment interaction with pre-existing natural fractures.

This paper sheds light on the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model (Weng et al., 2011), with the Unconventional Production Model (Cohen et al., 2012) is presented. By applying this workflow to a realistic reservoir, we did an extensive parametric study to investigate the relation between production and treatment design parameters such as fracturing fluid viscosity, proppant size, proppant concentration, proppant injection order, treatment volume, pumping rate, pad size and hybrid treatment. The paper also evaluates the influence of unconventional reservoir properties - such as permeability, horizontal stress, horizontal stress anisotropy, horizontal stress orientation, Poisson's ratio and Young's modulus - on production. Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fracturing fluid viscosity for all of these parameters. More than fourteen hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design.

This paper illustrates how this unique workflow can identifies the optimum fluid and proppant selection that gives the maximum production for a given reservoir and completion. In addition, the parametric study shows how these optimums evolve as a function of reservoir and treatment parameters. The results validate several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. The study explains why slickwater treatments should be injected at maximum pumping rate and preferably with 40/70 mesh sand. It also illustrates why reservoirs with high Young's modulus (such as the Barnett shale) can be stimulated effectively with slickwater. Another key finding is that the optimum fluid viscosity increases with treatment volume.
Effect of Reservoir Porosity and Clay Content on Hydraulic Fracture Height Containment
Authors: Liu He , Wang Han , Wu Heng'An , Wang Xiu'Xi
Published: March 2015

The technique of hydraulic fracturing is an essential way for reservoir stimulation. Prediction of hydraulic fracture geometry has been a difficult challenge in petroleum engineering. A 3D non-linear model is established for simulating hydraulic fracturing processes based on the ABAQUS code. The fluid-solid coupling equations consist of rock stress equilibrium, porous fluid mass conservation, Darcy's law and effective stress principle. The differential equations are discretized in finite element form and solved. The cohesive elements based on damage mechanics are adopted to model the fracture initiation and propagation.

A typical hydraulic fracturing process of a horizontal well in Daqing Oilfield, China is simulated with this model. Variation of proppant concentration during the fracturing procedure is taken into account by the user-subroutine we developed. The bottomhole pressure evolution obtained from the simulation is consistent with the field-measured data. Thus the model is verified.

For vertical fracture, the effect of formation porosity and clay content on fracture height containment is investigated and discussed. The rock properties are connected to porosity and clay content by a set of formulae. The results show that larger porosity and clay content could confine the fracture height. As the porosity of the pay layer increases, the permeability increases while the elastic modulus decreases. Since the fracturing fluid leaks off into the reservoir more easily for larger porosity formations, the fracture height decreases and the bottomhole pressure drops. With the increase of the clay content of barrier layers, the elastic modulus decreases and the tensile strength of rock material increases. And the fracture height will decrease as the material is more difficult to be damaged for larger clay content formations.

Our work can provide a new understanding of fracture height containment and could benefit the design and practice of hydraulic fracture treatment.
Thermally Stable Cutter Technology Advances PDC Performance in Hard and Abrasive Formations, Kuwait
Authors: Hussein Ali , Al-Anezi Nayef Abdulla , Al-Sarraf Adel Q. , Dhabria Akshaya K. , Baqer Hussain A. , Maliekkal Harish , Ghoneim Osama , Zhang Youhe
Published: March 2015

Efficiently drilling the 16" hole section in high temperature/high pressure (HTHP) conditions through hard/abrasive Jurassic formations in Kuwait's oil fields has been a distinctive challenge for more than a decade. The difficult sequence of lithologies starts with abrasive Zubair sand (with pyrite) followed by reactive Ratawi shale and then hard carbonates (UCS 10–30kpsi). The Zubair is approximately 1300ft thick and has historically been drilled with four/six rollercone TCIs or a combination of two TCIs and two PDC bits or two/three PDCs. The objective has been to reduce the total number of bits/trips and ultimately drill the Zubair and as much Ratawi as possible with one PDC bit.

Initial attempts with PDC were encouraging, but not economically successful compared to rollercone cost/ft. To improve performance, an FEA-based modeling system was used to predict downhole behavior. Based on these knowledge gains, a new PDC bit design was produced with optimized blade orientation and reconfigured cutting structure. Although the new design did improve performance, the drilling team concluded the PDC shearing elements were unable to withstand the HTHP environment (thermal degradation) and vibration induced impact damage. The operator required new technology to enhance cutter longevity.

To deliver a suitable solution, new cutter technology was developed using a two-step manufacturing process high temperature/high pressure pressing technique. Laboratory tests indicated the new style cutter has significantly increased resistance to abrasive wear and thermal fatigue compared to standard cutters without compromising impact resistance.

The HTHP cutters were run in a nine-bladed PDC with outstanding results setting a new Kuwaiti single run Zubair footage record (1302ft) and Zubair/Ratawi field footage record (1347ft). The authors will discuss the application challenges and resulting performance improvement. Offset analysis will document a performance step-change that saved the operator an average of 10 days of rig-time (﹩500,000USD).
Feasibility of Using Laser Bit Beside of Common Bits to Drilling Slim Holes
Authors: Bazargan M. , Jalalifar H. , Koohian A. , Habibpour M.
Published: March 2015

The capability level of rotary as well as first generation drilling operation could not be matched for deeply drilling programs. To reach that deep, the increasing in drill string length could also cause an additional constraint on hydraulic performance. The operation of slim hole drilling has significant potential to reduce well costs. This cost might be savings are especially important with increased demand for reduced capital finance under current economic conditions in the Iranian oil and gas industry.

This savings achievement could be caused by use of smaller drilling rigs, work over rigs, reduced casing size, reducing requirement for drilling consumables and other costs associated with hole size. Otherwise, using laser irradiation for drilling operation can save cost little more higher look like do not using casing and perforation in reservoir layer for slim hole which are drilled by high power laser systems.

As the matter of fact, Cost savings achieved from slim hole drilling could be offset by inability to effectively transmit the weight to the bit, increased mechanical failures of drill pipes and tools and reduced the well bore instability effects in particular, in drilling operation at greater depths This paper investigates the effects of borehole parameters during laser drilling operations in the case of slim hole.

Introduction:

For last 30 years old experiments and studies had shown laser drilling as benefit technical operation[27]. The earliest studies were resulting enhancing tunneling machines to be used to mining industry improved by lasers tools[21][22]. Lasers start works on industry with very low power but produced large wavelengths and it wasn't safe for industrial use The old methods of Drilling was the Rotary operation and drilling industry was developing[1][6].

Since the rotary drilling superseded cable tools drilling, there was a huge break for the oil industry when cable tool drilling had been replaced to the rotary drilling[18]. Developing started almost a century earlier, the basic method of using them was to reach gas and oil reservoir in our formations[24]. The current drill bits are very widely used tool for rough layer and drilled them in non-metallic goods in general and in step by step based products in regular. It's most widespread use is encountered in the home construction industry, really weak on the case for plumbing and electrical installations[23].
An Integrated Model for Selecting the Best Fuel to Develop in the Value Chain of Natural Gas
Authors: Mousaei Ahmad , Ghadirian Abbas Ali , Hatefi Mohammad Ali
Published: March 2015

A value chain is a series of events that takes a raw material and with each step adds value to it. Global interest in the application of natural gas in production and transportation has grown dramatically, representing a long-term, low-cost, domestic, secure, etc. alternative to petroleum-based fuels. Many technological solutions are currently considered on the market or in development that address the challenge and opportunity of natural gas.

In this paper, an integrated model is introduced for selecting the best fuel to develop in the value chain of natural gas through the four options:Compressed Natural Gas (CNG), Liquefied Natural Gas (LNG), Dimethyl Ether (DME)and Gas-To-Liquids (GTL). The presented model uses the Multiple Attribute Decision-making (MADM) techniques to select the best fuel in the value chain of natural gas based on the criteria such as market situations, technology available and transportation infrastructure. The model recommends some key guidelines for two branches of countries i.e. those have natural gas resources and the others. We believe that applying the proposed model helps the oil &gas / energy ministries in most effective and productive manner dealing with his complicated fuel-related production and transportation decision-making situations.
First Successful Application of an Environment Friendly Fracturing Fluid during On-The-Fly Proppant Fracturing
Authors: Al-Ghazal Mohammed , Al-Driweesh Saad , Al-Shammari Fowzi
Published: March 2015

With the increasing demand for natural gas, fracturing fluid technology needs to develop to enable optimized well completion operations with minimum ecological impact. The recent development of environmentally friendly polymer-free fracturing fluids — with superior operational performance —represents a major technological advance in the petroleum industry.

The use of these new fluids during fracturing operations has the following benefits: minimized environmental footprint and formation damage, operational efficiency and simplicity, and maximized fracture conductivity.

This paper discusses the first successful deployment, of an environmentally friendly polymer-free fracturing fluid, during on-the-fly proppant fracturing in Saudi Arabia. Also, the paper discusses the optimum layout of the fracturing equipment used during the job execution.

The fluid was used to fracture a gas zone located between two water zones. Therefore, one of the main objectives of the treatment was to control the height of the fracture to not break through and contaminate the water-bearing zones.

In addition, the fluid exhibited a low friction pressure and excellent proppant-carrying capacity. Moreover, the overall cost of this fracturing operation is in line with conventional, polymer-based fluid fracturing approaches.

Evaluation of the post-treatment results demonstrated the following: very positive well productivity, improved fracture geometry (longer fractures with better height containment), and faster fracture cleanup time.
Field Optimisation of Acid Concentration of Visco Elastic Based Acid Using Fiber Optic Enabled Coiled Tubing (FOECT)
Authors: Dhufairi M.A. , Al-Mutairi S.H. , Ahmed D. , Bal Moustapha
Published: March 2015

Success of matrix stimulation treatments depend on the uniform distribution of treating fluids over the entire production/injection interval. Thus, when acid is pumped into a well, it naturally flows to the most permeable/least damaged zone. To avoid improper placement of acid into one interval of a zone of different injectivities, diversion techniques can be applied. Diversion can be accomplished by either mechanical means or chemical means.

Diverting chemicals are deposited over the perforations or the formation. When deposited, they form a layer with a lower permeability than the formation it is covering. This imposes an additional pressure drop needed to penetrate the cake will cause the fluid to divert to another part of the perforated interval. Eventually, uniform injection is accomplished across the whole interval.

Different concentrations of diverting agents can be used to get the required diversion, but how to know if the diverter pumped is indeed diverting or not is a challenge. Bottom-hole pressure or temperature responses can be checked during the job to get an idea if diverter is working properly. Thus, Fiber Optic Enabled Coiled Tubing with Fiber Optic Enabled Bottom-hole Assembly(FOEBHA) with pressure and temperature sensors for real-time downhole measurements and Distributed Temperature Sensing (DTS) is the best solution available.

This paper describes the use of different concentrations of diverter i.e. visco elastic diverting agent and the behavior responses of downhole parameters with their usage.
Joint inversion of time-lapse crosswell seismic and production data for reservoir monitoring and characterization
Authors: Liang Lin , Abubakar Aria , Habashy Tarek M.
Published: March 2015

We present a fluid-flow constrained inversion approach for joint interpretation of time-lapse seismic and production data. In this approach, the full-wave formseismic inversion is integrated into the traditional history-matching process. Hence, the interpretation of time-lapse seismic data is constrained by the fluid-flow physics in the reservoir. The key component in the workflow is a fluid-flow simulator, which computes not only the production data in the wells, but also the temporal and spatial distribution of fluid properties, such as fluid saturation and pressure. These fluid properties, together with prior rock properties, can be transformed to acoustic properties using the prescribed petro-elastic model. A finite-difference frequency-domain acoustic solver is then used to simulate the time-lapse seismic responses on the reservoir. We use a multiplicative-regularized Gauss-Newton scheme to update the reservoir mode literatively until good match between measured and simulated data is achieved. The derivative of seismic data with respect to acoustic properties is calculated using the adjoint method, and then connected to reservoir parameter susing a chain rule derived from the petro-elastic model, while the derivative of production data with respect to reservoir parameters is calculated using the gradient- simulator method. A synthetic crosswell example is employed to demonstrate that the estimation of permeability and flooding front movement can be significantly improved from the joint inversion of time-lapse seismic and production data.
The Approach of CT-Dragged Hydrajet Perforating and Annular-Delivery Sand Fracturing Applies in Horizontal Wells
Authors: Yuxi Liu , Xianggang Yue , Guoliang Zhang , Long Yu , Chengyu Lan , Peng Liu , Minghui Luo , Shanjun Zheng , Hong Xia , Liguo Li , Xianlong Liu , Yunping Chi , Yuebao Liu , Shifa You , Jibao Ma , Tingting Zhou , Wei Liu , Xinyou Wu
Published: March 2015

Multi stage fracturing of horizontal wells is quickly creating the same'step change' as when vertical wells first went horizontal (Rob Hari, 2010).Following the implementation of multistage fractured horizontal well, the operation scale enhances unceasingly.

The new technique need to be complied with some characteristics, such as high fluid delivery capacity, large fluid amount per well and uninterrupted multi-stage execution. But small open area and big friction drag of tubing or CT become the vital constraint in increasing displacement.

This paper will show the new approach of CT-dragged hydrajet perforating and annular-delivery sand fracturing applying in horizontal wells, and discuss technical measures for estimating and optimizing some construction parameters in two stages of the approach, finally describe two targeted operations.
Development Strategies of JZ25-1S Thin Oil Rim Reservoirs with Big Gas Cap
Authors: Ge Lizhen , Yang Qinghong , Tong Kaijun , Fang Liwen , Su Yanchun , Zhang Yingchun , Cheng Dayong
Published: March 2015

JZ25-1S oil field located in Bohai bay which has a thin oil rim with a gas cap on top and aquifer below, and this field has to supply fuel gases to the residents. To achieve maximum oil recovery, force balance between aquifer drive, gas cap expansion, and viscous withdrawal shall be carefully studied for this type of reservoir at various stages of the production lifecycle.

Available methodologies including analytical, and simulation are used to optimize the development strategies, including well type, the well location, drawdown and so on.

Using horizontal wells to develop the thin oil rim, the horizontal length parallels with the GOC and OWC, the horizontal section length is 300–400 m nearby, the stand off over the OWC is 1/3 of the oil column if the gas capindex is more than 1.5, and the optimized drawdown of the horizon well is recommended 0.3–0.6MPa ; while the gas capindex is less than 1.5 and the aquifer is stronger, the stand off over the OWC is 1/2 of the oil column, the drawdown is recommended 0.5–0.8MPa; And making good use of the gas and aquifer energy at initial stages of production, then using water flooding for the reservoir which gas cap index is less than 1.5 and the aquifer is weak.

A number of horizontal wells were optimized and drilled in JZ25-1S field after optimizing the development strategies. The initial oil rates are from 943-2830bbl/d under the optimized drawdown.

The management of GOC and OWC movement is extremely critical in this kind of oil field. Based on the achieved parameters, these wells display significant higher oil production with delayed water coning and slower gas channeling.

Both simulations and production data demonstrate that the JZ25-1S development strategies gain success, using horizontal wells balance GOC and OWC to explore hydrocarbon, and achieve maximum results, which provides the theoretical and production data for development optimization of thin oil rim reservoirs with gas cap in Bohai Bay.
Sichuan Shale Gas Microseismic Monitoring: Acquisition, Processing, and Integrated Analyses
Authors: Dwan Fa , Qiu J. , Zhou M. , Yuan R.S. , Zhang Z. , Jin L. , Wang S. , Li X. , Lin M. , Liang B. , Deng C. , Liang S. , Englebrecht L. , Van Dok R. , Walter L.
Published: March 2015

The ability to estimate the stimulated reservoir volume and to enhance the effectiveness of hydraulic fracturing operation is fundamental in field development planning and critical to optimizing well completion in unconventional gas exploration and production. Microseismic Monitoring (MSM)survey provides essential observations study how induced rock volume responds seismically under field hydraulic fracture stimulation. Recent advanced microseismic technology with further development can provide real-time monitoring and interpretation which will improve hydraulic fracturing efficiency and better EUR, stop induced fracture development toward fault zones, and avoid connecting water-bearing layers. Advanced processing can enhance weaker microseismic signal, which provides a more complete Microseismically-Stimulated Reservoir Volume (M-SRV). M-SRV is essential to build the 3D understanding of the induced fracture network under various stimulation designs in volumes and in patterns from each fracturing stage.
Modelling the Transient Behaviours of the Kinetics in the Transesterification of Palm Oils Reveals Prospects for Customisation of Esters for Drilling Fluids Formulation
Authors: Okeke Eric O.
Published: March 2015

This paper discusses the prospects for customizing esters derived from palm oils as part of the first phase of a study to develop new drilling fluids. This phase evaluates the feasibility and prospects for customizing such esters in order to fully define experiments and all analytical conditions for realizing the objectives of the entire study. Published studies in transesterification show products from various vegetable oils for different applications including biodiesel production. Vegetable Oils consist of triglycerides (TG) 90 - 98 % by weight, small diglycerides (DG) and monoglycerides (MG), while palm oil contains TG 95.7%, DG 3.7%, and MG 0.6%. Transesterification of vegetable oils with alcohol is characterized by multiple consecutive and reversible reactions. TG is converted stepwise to DG, MG and finally glycerol (GL). We are particularly interested in palm oils (developed in large plantations in Nigeria). ASPEN HYSYS 7.3 was used to model the non acid catalyzed transesterification involving three reactions each with methanol for conversion of TG, DG and MG under steady state and transient conditions in a CSTR at varied reaction conditions and time to produce varied esters properties. Results from the model show prospects for customizing esters derived from the transesterification of palm oils and realizing their application in drilling fluids formulation.
The World's First Real Time Logging with Tractor in an Extended Reach Horizontal Well with Proof of True Stimulation
Authors: Arukhe J.O. , Ghamdi S. , Dhufairi M. , Duthie L. , Omairen K.
Published: March 2015

Although engineers have employed tractor interventions relatively extensively in well stimulation of extended reach wells in this field, an outstanding challenge in the field and even in the industry has been to conduct real-time acquisition of inflow or production profiles and to evaluate treatment effectiveness in extended reach open hole horizontal wells. This challenge was overcome from real-time electrical to optical (EtO) water injection profile measurements simultaneously with running a tractor. The motorhead assembly (MHA) of coiled tubing (CT) was successfully wired through a tractor to allow the world's first successful real-time acquisition of an inflow profile in an extended reach open hole horizontal power water injector in one of the current largest field development projects in the world. The well, located on one of two finger islands, was completed to a total depth of nearly 30,000 ft (over 9.10 km) MD; making it the deepest open hole section logged in the field development outside the normal reach of tapered CT for well intervention. The intervention on the well was successfully carried out through the application of a 2-in. tapered CT and well tractor.

The well's treatment involved 3,850 barrels of emulsified acid recipe in 14 stages. A comparison of the pre- and post-stimulation injectivity indices showed an eightfold injectivity index improvement from 53 bpd/psi to 400 bpd/psi. The resulting marked improvement in injectivity from acid stimulation also revealed the benefit of informed decisions from the real-time fiber optic distributed temperature sensing (DTS) in fluid placement.

Effective stimulation was critical for increasing injectivity and creating conductive flow paths between borehole and the reservoir. Relatively good transmissibility between the injectors and producers during the commencement of a field-wide waterflood was crucial because of a relatively high viscosity tar layer between the overlaying oil column and aquifer. This tar layer was a challenge for assuring adequate aquifer support to the producers because of their partial sealing nature. For reasons of optimizing sweep and recovery, the placement of water injection wells and requirements was focused around the flanks of the structure. The ability to employ real-time information to effectively stimulate and log inflow profiles in extended reach wells has provided assurance that stimulation can serve as a technical and an economic solution for addressing the relatively high skin damage post drilling and completion. Other practical applications of the success outcome from the real-time acquisition of inflow profiles includes the reduction in the transmissibility uncertainty between the producers and injectors in the field development partly because of the availability of better quality data for reservoir simulation or characterization purposes.
Application of Walkaway VSP for Improving Seismic Imaging of Fractured-Cavernous Carbonate Reservoirs
Authors: Liu Yimou , Liang Xianghao , Zhou Yi , Liu Shiyong , Wang Xiaofeng , Li Yanpeng
Published: March 2015

Ordovician carbonate rocks are widely distributed in Tarim basin, western China, and they are the important yet very difficult targets in the oil and gas exploration and development. The carbonate reservoirs are ultra-deeply buried and their storage spaces are mainly secondary dissolved caves, holes and fractures of various sizes. The main challenges for seismic imaging are that the target formations are usually in very low signal-to-noise ratio due to the seismic attenuation, and the reservoir media are strong heterogeneous (caused by caves and holes) and having varying degrees of anisotropy (caused by fractures). Conventional processing techniques fail to image and identify the fractured-cavernous reservoirs accurately. In order to better image and identify the reservoirs, an 8-azimuth walkaway VSP (with a maximum offset of 6600m from the wellhead and covers the 510m-6470m depth interval with receiver spacing 10m) was carried out to estimate the true amplitude recovery (TAR) factor, Q factor and VTI anisotropic parameters, and then proper energy compensation approaches and VTI anisotropic migration algorithms are introduced in the seismic processing flow. The results show remarkable improvement in seismic imaging, and the depth errors of the geological targets are reduced considerably.
Fill Cleanout Operations in Offshore Saudi Arabian Fields: Case Histories toward Improving Economics and Operational Logistics
Authors: Yateem K.S. , Qahtani H.B. , Saeed S.S. , Li J. , Aitken B.
Published: March 2015

Coiled tubing (CT) fill cleanouts have been in existence for over four decades and today account for approximately 30% of the services performed. Both CT and conventional jointed pipe offer a forward or reverse circulation mode to remove solids; however, using conventional water-based fluids, a sand cleanout method may apply excess hydrostatic pressure to the formation, resulting in some lost circulation to a sub-hydrostatic reservoir. Nitrogen (N2) can be used to reduce hydrostatics, but this requires a very precise job design and execution. Moreover, N2 use can have adverse logistical and economic implications - large amounts of N2 may be needed, especially in larger diameter wellbores and in horizontal wells.

Several cleanout methods have been utilized in the past, employing a variety of different approaches. CT historically has incorporated limited circulation rates, exotic/costly fluids and reversing circulation to remove solids. The use of CT to remove sand from wellbores was one of its earliest applications and continues to be an important service today.

This paper will discuss cost-effective solutions in Saudi Arabia, highlighting field cases and job optimization. The selection of the most appropriate sand cleanout method has to be based on both logistical and technical issues. This paper shows how to select the most cost-effective fills cleanout method for these wells. A few field cases are discussed to demonstrate the proper operational procedure, challenges and lessons learned. The combination of how to utilize the sophisticated solids transport software, downhole switchable nozzle, and proper operational procedure with the frequent evaluation of downhole conditions on site is essential to insure the fills cleanout is executed 100% successfully.
The Production Enhancement of NGL and Reduction of Pipeline Liquid Condensate Flaring with the Successful Implementation of Triethylene Glycol Dehydration Unit
Authors: Peng Kuang-Yao Brian
Published: March 2015

To meet the future sustainability requirement(1,2), major energy suppliers in the world have been pursuing the highest standards of environmental policy to contribute the conservation of natural resources through operation excellence and energy optimization.

Abqaiq Plant is the largest oil stabilization plant in the world. A small improvement in separation process could lead to significant energy saving and reduction of CO2 release for its large scale. The crude oil processing units at Abqaiq Plant have two major functions. First, crude feeds from oil field are stripped with steam which increases the moisture content of offgas from the oil stabilization column. Second, the low pressure offgas is pressurized to 450 psig for separation of NGL products. The final NGL product is transferred to the downstream refinery for further processing and the offgas from the NGL facility is transferred to the downstream gas plants for sulfur removal. For years, gas pipelines have been suffering from back pressure caused by liquid condensate accumulation in the pipeline. To reduce the back pressure, enhancement of NGL recovery is required but the challenge is to lower the deethanizer operation temperature without hydrate formation. As a part of the global downstream pipeline and plant optimization program, Saudi Aramco has invested $65MM capital expense for triethylene glycol (TEG) dehydration unit(3,4,5) at the world largest oil stabilization facility to reduce the frequency of pipeline scraping. The success of this project would eliminate 2 million pipeline scraping cost and 40 million of liquid condensate reprocessing and liquid flaring every year. The liquid condensate flaring has imposed a serious adverse environmental impacts and risk to operator exposure to hydrogen sulfide. Commissioning of the TEG dehydration unit was initially unsuccessful for the issue of plant piping network back pressure. To achieve the full benefits of the newly implemented TEG unit, the Abqaiq Plant operation engineering unit has utilized the advanced real time optimization (RTO) model to identify the root causes of failure. Process studies including the feasibility of steady state normal operating conditions and the piping flow estimations were completed by RTO data reconciliation model. Further offline studies for pressure drop analyses on piping networks were completed with additional pipe diameters and roughness data. The location of back pressure was identified by the advanced engineering tool.
Multi-Azimuth Seismic Data Imaging in the Presence of Orthorhombic Anisotropy
Authors: Xie Yi , Birdus Sergey , Sun James , Notfors Carl
Published: March 2015

Orthorhombic anisotropy is considered to be the simplest realistic symmetry for many geophysical problems. Orthorhombic anisotropy exhibits both HTI (Horizontal Transverse Anisotropy) and VTI (Vertical Transverse Anisotropy) effects, making seismic velocity varying with azimuthal direction as well as polar direction. In many cases, these effects are important by themselves and can be a target of special studies.

The presence of orthorhombic anisotropy poses challenges in wide azimuth imaging which has been rapidly developed for better illumination, better imaging, and better multiple elimination. Analysis of multi-azimuth (MAZ) data often reveals noticeable fluctuations in moveout between different acquisition directions, preventing constructive summation of MAZ images due to the azimuthal dependency nature of wave propagation in orthorhombic medium. On the other hand, the co-existing VTI effects of orthorhombic anisotropy can also cause well misties and higher order moveout.

Orthorhombic anisotropy can take into account the co-existing HTI/VTI effects. We have developed an approach for imaging in the presence of orthorhombic anisotropy, including orthorhombic velocity analysis and orthorhombic migration. Following Tsvankin's work, we put forward a ray tracing approach suitable for both weak and strong anisotropy which applies to both Kirchhoff and Beam PSDM. Aimed at the challenge in orthorhombic anisotropy model building, we have developed a practical workflow which combines the co-existing HTI/VTI anisotropy estimated through multi-azimuth tomography to form the orthorhombic model.

In this paper, we first describe our approach for imaging in the presence of orthorhombic anisotropy, including the newly developed orthorhombic ray tracing method and the newly developed practical method for orthorhombic anisotropy model building. We then demonstrate with both synthetic and real data from offshore Australia that our approach can successfully take into account the co-existing HTI/VTI effects, reduce the structural discrepancies between seismic images built for different azimuths, hence produce constructive summation of MAZ dataset, resolve well mistie to match with geology, and deliver a step-change in the final seismic image quality.