bluuebunny/crossref_metadata_2025 huggingface dataset:
The Impact of Water-Injection-Induced Fractures on Reservoir Flow Dynamics: First Applications of a New Simulation Strategy
Authors: Hustedt Bernhard , Qiu Yuan , Zwarts Dirk , van Schijndel Luc , van den Hoek Paul Jacob
Published: February 2016

We present benchmark simulations and a real-field application of a new coupled fracture growth / fluid flow simulator.

The coupled reservoir simulations compare well for various synthetic test scenarios. The application to a real five-spot injection trial demonstrates the importance of the new modelling tool for optimal reservoir management.

Introduction

In many fields secondary recovery is playing an increasingly important role to maintain oil production. The recovery of the remaining oil is a major task that, due to the complexity of many reservoir formations, requires an extensive knowledge of the subsurface. Probably the cheapest and most often applied technique to sweep a reservoir is a waterflooding project.

Injection of water in the reservoir formation is often accompanied by, unnoticed, induced fracture propagation. Dynamically growing or shrinking fractures have a huge impact on the reservoir management strategy and, if not handled properly, may risk the success of the whole water injection process. Hence, dynamic fracture propagation should be an integral part of a standard reservoir simulation study. Then, an optimal waterflood implementation may be achieved which guarantees an overall increase of recoverable oil.

Next to waterflooding are numerous other applications where induced fracture mechanics play a significant role in defining the reservoir behavior. Typical examples are water injections for reservoir pressure maintenance of e.g., green or brown fields, and safe disposal of produced water by re-injection.

In the past, varying approaches have been presented to study fluid flow and fracture growth during reservoir simulations. Implicit and explicit coupling techniques have been developed and tested for varying theoretical and practical scenarios. The main differences are to which extent the interaction and uncertainties of a coupled fluid flow-rock mechanics model are incorporated in the simulation tool. To our knowledge, these tools are not widely used in the industry on a standard basis, since the models need to be purposed-built and, therefore, require an extensive effort to be put into place.
Exploring the "Empty Quarter" - Early Experience and Lessons of a New Upstream Venture in Saudi Arabia
Authors: Allman-Ward P. , Voggenreiter W.
Published: February 2016

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

Under the terms of the Upstream Project Agreement ratified in November 2003,the South Rub Al-Khali Company Limited (SRAK) has entered into an agreement with the Kingdom of Saudi Arabia for the exploration, appraisal, development and production of non-associated gas, condensate and natural gas liquids in Contract Areas 1 (Blocks 82–85) and 2 (Blocks 5–9) in the South Rub; al KhaliBasin of Saudi Arabia. SRAK is an Incorporated Joint Venture between Shell(40%), Saudi Aramco (30%) and Total (30%), with Shell providing the technical lead.

Exploration activities under the terms of the Upstream Project Agreement are governed by a first five year exploration term and two subsequent five year exploration periods undertaken at the option of SRAK. Work commitments for the first exploration term encompasses a major seismic acquisition programme of16,000 km of 2D data and the drilling of seven exploration wells. The exploration acreage covers an area of approximately 210,000 km2, equivalent to10% of Saudi Arabia's land area. SRAK's exploration efforts will be focused on the Palaeozoic reservoirs. In contrast to the hydrocarbon-rich tracts within the Saudi Aramco Reserved Area some distance to the north, the remote SouthRub, al Khali Basin is only lightly explored, and the presence of a working(Palaeozoic) hydrocarbon system has yet to be demonstrated.

Eighteen months into the first exploration term, this paper focuses on the venture related as well as technical challenges that are being faced and how they are being addressed.
Physics-Based Well Design - Beyond the Learning Curve
Authors: Kline William E. , Chandler Karen , Keller Stuart Ronald , Ottesen Steinar , Gupta Vishwas , Tenny Matthew
Published: February 2016

In a drilling program, the design of wells has historically been an incremental process in which compiled experience from previously drilled wells is the principal driver for realizing drilling design. The efficiency of drilling in a field, and as a result, the cost, typically improves significantly initially, before reaching a point at which little improvement is achieved. The progression from the initial well to the final wells of a mature drilling program is often referred to as the "drilling learning curve." Rather than focus on getting the design right after several wells, it is possible to outperform the learning curve by developing and applying fundamental physics-based models and computational optimization engines up front to quantitatively analyze well design options. These proprietary tools have been applied extensively in field development planning, as well as in real-time, to ensure optimal drilling performance. This paper describes ExxonMobil's approach to physics-based modeling, advanced mathematical optimization, and real-time updating to achieve drilling performance that both accelerates and undercuts the historical learning curve. Specific business examples illustrating successful applications of this approach are presented.

Introduction

Optimal well design requires attention to both fundamental engineering principles and site-specific learnings. The drilling learning curve, which identifies adjustments to initial design parameters to improve overall well design, can frequently cut 50% or more from well costs over the course of a continuous program. While a variety of learning-based well design techniques have served the industry well, the biggest prize is achieved by utilizing physics and mathematics to shift the optimization process from the learning curve to the initial well design – getting it right the first time.

ExxonMobil's approach to going beyond the learning curve is based on routine application of proprietary technology that couples fundamental physics-based models with statistical analyses. The models enable the accurate prediction of expected drilling performance over a wide range of operational conditions. By accounting for downhole parameter uncertainty, engineers effectively optimize this performance over all expected scenarios.
Applications of Petrophysical Scale Reconciliation to Saudi Arabian Reservoirs
Authors: Worthington Paul Francis , Al-Ali Hussein Ali
Published: February 2016

Core data from three fields have been stress-corrected and upscaled so that they become notionally reconciled with wireline well logs along wellbore axes. The upscaling process draws upon logging tool response functions in a way that optimizes the correspondence between the smoothed core porosity data and density or sonic logs. It is demonstrated that there are significant differences between core-derived porosities at the core and log scales. These differences are tool-specific, and they transmit through to the log-derived porosity. Once a scale-reconciled log-derived porosity has been validated, it can be input to a core-derived porosity-permeability algorithm. Where this transform is based on compatible, upscaled core data, the results are significantly better than those from the conventional approach that is tied back to the core-plug scale. These observations have formed the basis for improved workflows for the petrophysical evaluation of porosity and the subsequent estimation of intergranular permeability. The approach can be readily extended to the evaluation of water saturation where low-invasion coring has taken place.

Introduction

Core-to-log integration is a fundamental petrophysical component of integrated reservoir studies, because it provides the groundtruthing for well-log analysis. Historically, log responses have been tied back to core data with little attempt being made to take account of the different scales of measurement. More recently, however, there has been a renewed interest in redressing this situation, even though it is recognized that a full reconciliation of core and log data might not be possible, because of the different volumes of rock sensed by these two types of measurement. Success at this stage delivers further benefits when porosity is used as a predictor for the evaluation of other parameters such as permeability.

In this paper, petrophysical scale reconciliation is examined from two specific standpoints. The first is to process conventional core porosity data so that they provide the best possible groundtruthing for the evaluation of porosity from density and sonic logs.
Optimizing Well Test Sequence and Duration Using Real-Time Pressure Transient Analysis (RT-PTA)
Authors: Adeyemi Olutope S. , Cribbs Myrt Eugene , Lindo Octavio
Published: February 2016

Both conventional and non-conventional well testing and sampling operations require some form of design a priori. Due to the uncertainties in input parameters during the test design stage, test sequence and duration are mostly adhered to especially when memory gauges are being used. These uncertainties are more pronounced during exploratory or appraisal testing; hence, being able to make adjustments throughout the testing operation can result in significant value creation, particularly when operating in a high cost deep water environment.

This paper describes how real time pressure transient analysis (RT-PTA) may be used to optimize test sequence and duration in exploratory well testing and sampling. Two case histories are presented that show the impact and value added by combining real time data acquisition, analysis and decision making in the test procedure. Value is achieved by making informed decisions to redesign the test sequence to better meet test objectives, improved stakeholder communication concerning the reasons for these changes and improvements in contingency planning. It is the authors' hope that these examples will be useful to our peers when engaging in Value of Information (VOI) discussions.

Several modes of deployment currently exist for downhole data acquisition and transmission to the surface in real time. Case histories showing results from the application of two of these deployment techniques are presented. While no effort has been made to demonstrate the superiority of one method over another, emphasis has been placed on the impact of enabling real time monitoring and analysis of data acquired during well testing operations. The two methods presented, tubing encapsulated cable (TEC) and an acoustic telemetry system (ATS), were deemed most appropriate for each specific application.

The suitability of this approach for conventional and non-conventional well testing and sampling, the ability to adapt this technique to different types of tests and of being able to revise test sequence in real time to more efficiently accomplish a given set of goals makes real-time pressure transient analysis (RT-PTA) very attractive.
The Potential of Multiple Fractured Horizontal Wells in Siberian Oil Fields
Authors: Butter M.K. , East L.E. , Kuvshinov K.
Published: February 2016

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

Many of the Western Siberia oil fields are being developed/exploited with hydraulically fractured S-shaped wells (vertical through the pay section).Horizontal wells are also used; however, in many of the fields these wells are out performed by the vertical fractured wells. The reasons for this appear to be poor vertical permeability and sub-optimal drilling and completions practices.

To better quantify the potential of an undeveloped area of a western Siberian oil field, five different well types were evaluated: Vertical, Vertical-Fractured, Slanted (80 deg crossing multiple layers), Horizontal (with a single layer), and Multiple-Fractured Horizontal wells. These well completion types were evaluated using a reservoir simulation model of a sector of the field. The results of this analysis demonstrated that the multiple fracture horizontal well completions outperform the other well types and that they can have a substantial positive impact on the economics of the field development.

With traditional fracturing and completion techniques, where packers or bridge plugs are used to provide zonal isolation, fracturing horizontal wells is a complex operation with increased risk and not always economical. New pin-point fracturing techniques can eliminate many of these problems and reduce risk. Recent developments in these technologies make it possible to perform the same type of aggressive frac jobs as currently performed in vertical wells, with large proppant volumes and large proppant sizes (12/18), at multiple selected locations along a lateral wellbore.

To realize the full potential of this type of completion plan, traditional thinking, regulatory barriers, and equipment limitations need to be overcome. This process has started, and some operators are currently planning trial multiple fractured horizontal wells to demonstrate the potential.

This paper illustrates the potential demonstrated by the development study and recent technology developments that will allow the placement of multiple fracs in horizontal wellbores and the practical aspects that need to be addressed for operators to fully capture the potential.

A number of operators have firm plans to perform such fracs in horizontal wells. If performed in time, approval will be sought to present case histories in this paper.
Production-Induced Deformations Outside the Reservoir and Their Impact on 4D Seisimic
Authors: Kristiansen Tron Golder , Barkved Olav Inge , Buer Kjell , Bakke Roger
Published: February 2016

This paper is reviewing 4D seismic data from the Valhall field located in the chalk province on the Norwegian continental shelf. The field is monitored with 4D seismic and is the first field in the world to be monitored with permanent installed cables at the seafloor. This concept, including 120 km cables trenched into the seafloor above the field, is providing seismic on demand for reservoir management purposes and is called Life of Field Seismic. This paper will focus on the seismic observations of production induced deformations outside the reservoir at Valhall and will review the theory behind the deformations, how they impact the seismic velocities and the use of 4D seismic for reservoir monitoring. The paper will present integration of relevant theories, numerical modelling and results from laboratory experiments.

The work presented should have applications to other fields where even limited reservoir compaction will take place. How significant the reservoir compaction will be is dependent on the structural geometry, rock properties of the surrounding rock, reservoir thickness, the compressibility of the reservoir, the pore pressure depletion and if any weakening of the rock takes place during secondary or tertiary recovery processes. The methods presented in the paper can also be used to improve the uniqueness of the static geologic model, the dynamic flow model and the geomechanical model and, hence, result in a more unique history match of the reservoir as well as improved future prediction.

The main technical contributions from this paper are a detailed review of theory, laboratory and field data of relevance from a well instrumented field under seismic surveillance. The paper will also outline how integration of geophysics, geology, geomechanics and reservoir engineering can produce better reservoir performance prediction based on new workflows. The paper will also show how a problem of production induced deformations outside a reservoir, with corresponding velocity changes, may be used as an advantage in reservoir performance prediction in the future.
High-Resolution Static/Dynamic Modelling and 3-Phase Streamline Simulation in Complex Fluviatile Reservoirs
Authors: Olewczynska Marzena M. , Grotsch Jurgen , Al Jundi Jamal , Rao Shankar
Published: February 2016

This paper presents the application of high-resolution static and dynamic modelling in complex faulted fluviatile sandstone reservoirs. It is based on results of an integrated study of one of AFPC's fields in the Euphrates Graben, Syria, with the Cretaceous Lower Rutbah and Triassic Mulussa F1 & F2 forming the three main reservoir units. It describes the modelling challenges and the advantages of high-resolution models in reproducing the dynamic reservoir processes as observed from well data. It also shows how a dynamic process-based modelling workflow resulted in history match improvements and higher reliability of predictions. Subsequent field implementation of the project recommendations provided the ultimate validation of the modelling approach and demonstrated the predictive value of the models.

The paper also highlights the added value of 3-phase streamline simulation in full field history matching and improving the understanding of flow paths in the reservoir as a result of the interplay of fluvial channel sands and numerous fault juxtapositions. It compares streamline simulation with the traditional finite difference simulation results and describes the strengths and weaknesses of streamline simulation applied during history matching.

The Reservoirs

The investigated field has three main reservoir formations, which are the Lower Rutbah (RUL), Mulussa F1 (MUF1) and Mulussa F2 (MUF2), shown in a schematic cross section in Figure 1.

The Mulussa F sequence (MUF) is dominated by fluvial sandstone bodies alternating with flood plain fines and soil horizons. The reservoir quality of sands is good (average net porosity of some 16%, permeabilities ranging from 30 to 1000 mD, average oil saturation of 83%). The Triassic Mulussa is separated from the overlying Cretaceous Lower Rutbah formation by the regional BKL unconformity, which resulted in partial erosion of the formation within the field area, in particular in the western part. Hence the MUF1 varies greatly in thickness over the field, whereas the MUF2 has a layer-cake architecture (at the level of major stratigraphic units). Another key difference between the MUF1 and the MUF2 formations is the N/G ratio, which is high in the MUF2 (50–70%) and low in the MUF1, where it only attains 30%.
Optimizing Drilling Performance by Wellbore Stability and Pore-Pressure Evaluation in Deepwater Exploration
Authors: Klimentos Theodore
Published: February 2016

This paper discusses the most important drilling hazards related to borehole instability and pore pressure in deep water wells. A case study from a deep water well, which has experienced wellbore stability and loss of circulation problems, especially over intervals with higher angles of hole deviation, is presented. The answers provided by the study included properties, such as, recommended mud-weights (minimum & maximum) as a function of angle of deviation, rock strength and computed pore pressure. The determination of rock strength along with the optimum mud-weight windows improved overall the drilling performance in the next deep water well by minimizing washouts, loss of circulation and optimizing casing design by elimination of unnecessary casing strings. Moreover, improvement of bit performance was achieved by using the predicted rock-strength values. As a result, drilling time and well construction costs were significantly reduced.

Introduction

Wellbore stability and pore pressure related issues, especially in deep water blocks, cause frequently serious problems during drilling, logging and production operations. The narrow pore pressure and fracture gradient (PPFG) windows necessitate multiple casing strings to reach the target reservoir formations. Errors in predicting PPFG windows could result in significant loss of rig time and even failure of wells.

The removal of rock during the drilling operation disturbs the natural rock formation that is being subjected to a state of compressive in-situ stresses at depth. The redistribution of the stresses around the hole thus produces stress concentrations at or near the borehole wall. Such a high stress buildup around the wellbore may lead to a number of hole problems that include stuck pipe, borehole collapse, sloughing shale and excessive fill. Several billions of dollars are lost each year worldwide directly or indirectly caused by wellbore stability and pore pressure related problems. Therefore, in order to fully obtain the benefits of the directional drilling technology, wellbore stability analysis and pore pressure prediction has been of increasing demand in the planning stage of the wells, especially in deep water where exploration and field development costs are very high.
A Method To Simultaneously Describe Gravity and Imbibition in Fractured Reservoir Simulations
Authors: Boerrigter P.M.
Published: February 2016

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

In densely fractured reservoirs one has to rely on natural mechanisms like capillary imbibition or gravity to recover oil from the matrix reservoir rock. Capillary forces are an efficient displacement mechanism for rocks that are waterwet: these rocks prefer to hold water over oil and, once exposed to water via the fracture system, strongly absorb water thereby expelling oil to the fracture system, from where it can be produced. The alternative situation, where the rock prefers to hold on to oil, also exists (oil-wet or mixed wetrock). In such cases, the most effective way to produce oil, is to rely on gravity. By depletion or via gas injection a gas cap can be formed in the fractures system. This gas surrounds the oil in the tight matrix rock and, because gas has a lower density than oil, the oil will start to drain from matrix stacks into the fracture system due to gravity. In actual filed cases, usually both gravity and some degree of imbibition contribute.

The standard approach in fractured reservoir simulators is to describe fractures and matrix rock as separate systems that can interact with each other(the dual continuum approach), where interaction between matrix and fracture system is governed by shape factors. A proper description of GOGD processes in reservoir simulators is complicated by the nature of gravity to act only vertically and not in all directions as is the case for imbibition and depletion. This paper describes an extension of the dual continuum methods that allows a simultaneous accurate description of gravity and imbibition processes. A comparison is made with methods proposed in the literature and available in commercial simulators. The method has been successfully applied to study fractured reservoirs where gravity and imbibition effects both contribute.
Improved Production From Mature Gas Wells by Introducing Surfactants Into Wells
Authors: Jelinek Wolfgang , Schramm L.L.
Published: February 2016

A very common problem of mature gas fields is liquid loading. If gas wells suffer from liquid loading production is decreased. If most or all the wells suffer from this problem, then effectively the recovery factor and reserves are reduced. Therefore engineering and operational attention is required to improve operational performance through production enhancement and optimisation.

The reason for liquid loading is liquid accumulation in the well bore due to increased liquid gas ratio (LGR) at insufficient gas production rate and gas velocity. Liquid loading is not always obvious but can be verified through the critical velocity and nodal analysis. Theoretical and field investigations deliver a wide range from 5–20 ft/sec for the minimum critical velocity for continuous removal of liquids.

There are several production enhancement techniques available to accelerate production and to prolong the effective producing life of gas wells with liquid loading problems. One method is to reduce the effective density and surface tension of the produced fluids by using surfactants as foaming agents. Foaming is an effective method because reservoir energy is utilized. But the application of surfactants to lift liquids has to fit certain gas well production conditions.

A key factor is the selection of the most effective surfactant without damaging the reservoir. The important criteria and tests for screening to determine which surfactant works best include, but are not limited to surface tension.

Depending on technical and economical limitations various methods of introducing surfactants into the well are used and several possibilities have to be taken into account. Batch or soap sticks for example are not only the simplest methods but also solutions with low initial costs. Nevertheless from a certain point automated and continuous injection should be the preferred solution as for example the installation of a capillary coiled tubing.

For managing production decline in mature gas field environments the correct application of surfactants on gas wells with liquid loading is an effective solution. Surfactants are a production optimization opportunity and can be economically used to gain incremental production from depleted gas reservoirs with liquid loading problems.
The Belanak FPSO Project - A Description of the Challenges in Designing and Building One of the Most Complex FPSOS to Date and the First To Incorporate LPG Processing and Export
Authors: New M.E. , Smith J.E.
Published: February 2016

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

The Belanak FPSO was installed in the Belanak Field in October 2004 and should reach full production in the 3rd quarter of 2005. It will form the central production hub for a number of fields in Indonesia's West Natuna Seaarea, including Belanak, Belut, Kerisi and Tawes. ConocoPhillips is the operator for Block B with Inpex and ChevronTexaco as equity partners. Belanak has the capability to process and export 350mmscfd of sales quality gas, up to100,000 bpd of stabilized crude and 23,000 bpd of LPG in separate propane and butane streams.

Flowlines from two 24 slot wellhead platforms transport raw well fluids to the FPSO, where they are processed and exported as crude via a loading buoy, gas via pipelines to Malaysia and Singapore or as LPG to a separate storage tanker to be moored in the Belanak Field. The Belanak facilities are designed for a 30 year life and offer considerable flexibility to accommodate future fields and deal with incoming hydrocarbon streams as well as deal with H2S, CO2, Mercury and Mercaptans.

The vessel was designed and built in Asia with project management and design being conducted in Singapore, the 285m hull was fabricated in China, and the topsides were built and integrated in Indonesia. With approximately 25,000tonnes of topsides process equipment which includes LPG fractionation as well as 1.2 million barrels of oil storage, Belanak is one of the most complex FPSOs built by the industry to date.

This paper will further describe the Belanak FPSO and discuss some of the challenges that the operator and its contractors faced in designing and delivering this production facility on schedule and within budget expectations.
The Control of fracturing and dolomitisation on 3D reservoir property distribution of the Asmari Formation (Oligocene-Lower Miocene),
Authors: Aqrawi Adnan A.M. , Wennberg Ole Petter
Published: February 2016

The Asmari Formation (Oligocene-early Miocene) is the most important reservoir in the oilfields in the Zagros foreland of the Dezful Embayment of SW Iran. The carbonate reservoirs of the Asmari Formation are characterized by low matrix permeability, and effective drainage is dependent on the occurrence of open fractures. The fractures have been formed during the Zagros Orogeny since late Miocene, which is also responsible for the geometry and formation of NW-SE trending anticlinal traps. Dolomitisation is another factor controlling reservoir qualities as dolostones in general have higher porosities than limestones.

The fractures are typically stratabound and sub-perpendicular to bedding. The density and dimension of fractures are controlled by the mechanical stratigraphy, which is controlled by the depositional environment and cycles. In the platform top sequence, the Dunham's (1962) texture classification appears to be the most important factor controlling the Fracture Intensity (FI) rather than the mechanical layer thickness. Mud supported textures (mudstone and wackestone) have higher FI than grain supported (packstone and grainstone). The fracture density is high in the vicinity of faults.

Two main types of dolomite fabric are recognised; finely crystalline pervasive dolomite (<20µ) replacing mud-rich facies; and combinations of finely crystalline replacive dolomite surrounded by coarser dolomite cement (up to 100µ) in grain-supported facies. Dolomites have an evaporitic signature, based on geochemical and petrographic data, with a general upward increase in the abundance of both anhydrite and dolomite. Dolomite replacing the mud-dominated facies occurs as thinner beds, less extensive aerially forming the top of stratigraphic cycles deposited during highstand, and has lower reservoir quality, particularly as microporosity. Contrary, dolomite replacing the grain-dominated facies exists in thicker and more extensive beds forming the bottom of stratigraphic cycles deposited during early transgression, and these have better reservoir quality, particularly if leached or coarsely crystallined.

General Geology

The Dezful Embayment of SW Iran is one of the rich oil provinces in Middle East, see Fig. 1. The structural and stratigraphic features of Dezful Embayment have been investigated continuously since mid-last century (e.g. Haynes and McQuillan, 1974; McQuillan, 1985; Blanc et al., 2003, Wennberg et al. 2006 & 2007, Ehrenberg et al 2007). Most oilfields in this region are asymmetric anticlines having NW-SE trend as in Fig. 1.
History Match of an Old Waterflood: Dealing with Decades worth of Data from Hundreds of Wells
Authors: Belova Natela V. , Berul Ludmila , Sentyurev Andrey V.
Published: February 2016

Introduction

The main objective of the mature fields development optimization is the value adding through extension of field life. While elaborating field development additions, an operating company meets a number of problems falling into two categories:The problems associated with the quality and quantity of initial data (ID). Very often, when the development history counts more than 20 years, some well data, for instance, formation pressures, become unavailable. Well logs and well tests can be missing, if not properly archived. Moreover, the data may be complete, but the formerly used methodologies (e.g. the use of well cluster metering units) and instrumentation may have an adverse influence on the accuracy of production, WC, injected water, and formation pressure measurements.The problems associated with decision supporting instruments, e.g. a 3D dynamic model, or reservoir engineering analysis, used for elaboration of recommendations.

This paper illustrates the authors' approach to the mature field development optimization, and providing an example from the Schlumberger Consulting Services practice. The project was completed within a 4½-month timeframe.

Optimization of development envisages the following job types:Elaboration of methodology of ID quality control;Creation of a program of idle low-productive or high-WC wells rehabilitation;Building of a 3D full-field geological and dynamic models being able to serve for development optimization, and elaboration of a program of well intervention.

Upon analysis of development history and accounting for the full-field 3D model outcomes, we suggested to the operating company the following ways of making improvements to development:Well intervention programs for selected wells;Rearrangement of existing water injection patterns within the development cells;Redistribution of water injection between the development cells.

Field Brief

The field is being developed since 1970. A total of 1419 wells were drilled (Fig. 2). The target interval is the Bashkirian. Now the filed has 417 active producers and 165 injectors. The oil recovery is driven by water flooding. The Bashkirian contains 7 pay zones. Marked regularities of reservoir parameters distribution and thickness changes have not been revealed.

The absence of geological and geophysical regularities in distribution of parameters and the absence of impermeable seals between pays hampers the assessment of a pay-based reserves depletion.
Reconciling subsurface uncertainty with the appropriate well design using the Mechanical Earth Model (MEM) approach
Authors: Goodman Harvey Edwin , Connolly Peter
Published: February 2016

The involvement of the well engineer (WE) competency from the earliest phases of exploration is reaping economic benefit for major capital projects (single wells costing at least $25,000,000 US). As the geological and geophysical modeling work of the Explorationists matures and the subsurface picture becomes clearer, the appropriate well design flexibility is being achieved using Mechanical Earth Model (MEM) technology. This approach to well planning is particularly beneficial for deepwater exploration.

For deepwater subsalt plays, the capital outlays are immense, with single wells costing up to $100,000,000 US. For these projects, MEM technology has been found to be extremely valuable, particularly in characterizing drilling risks associated with well exit points below salt where in-situ stress perturbations can occur. These stress perturbations are being reliably mapped using MEM techniques and the consequences to borehole stability addressed. An example of principal stress rotation gleaned from a deepwater MEM and the consequences to borehole stability is summarized in this paper.

Introduction

Formation strength and in-situ stress are the key components of the Mechanical Earth Model (MEM) critical to well engineering design. Figure 1 shows rock stress and strength values (yellow shading) that are calibrated to formation properties and offset well performance criteria to the left. For instance, formation layer rock physics or elastic moduli values must be in agreement with the lithology types coming from the geological model and the impact on formation strength and stress character reconciled. Drilling performance for offset wells, such as rate of penetration (ROP) modeling, is also used to constrain the formation strength estimate. Production history is a general term that includes hydraulic fracture and sand production performance in the reservoir. Core data is used to constrain the static elastic moduli values estimated from acoustic data sources.

Figure 1. Mechanical Earth model (MEM) flowchart with key components formation strength and in situ stress.

Figure 2 displays rock physics impact on formation strength and elastic moduli with changing porosity at a single depth. As porosity decreases, the corresponding rock modulus and strength increases. When formation layer modulus is known, and the distribution of these layers is also known throughout the MEM volume, the corresponding stress distribution through this volume can be reliably estimated using numerical modeling techniques. Below it will be shown that in tectonically active areas, the high modulus formation beds are propagating relatively higher in-situ stress across the geological structure.
Planning a Deepwater Well For All Seasons; Platina-2, A Combined Appraisal/Development Well
Authors: Brown Ian James , Ramlogan Marsha Giselle , McMurray Trevor
Published: February 2016

Due to the punitive cost of drilling deepwater wells with 5th/ 6th generation rig rates flirting around $500,000/day, the need arose within the BP Angola Business Unit to plan a combined appraisal / development well as the first well on Platina West; a field which exists on seismic but remains unconfirmed with a well.

The plan for this combined 'well for all seasons'* would have to be based upon high quality seismic and offset information from recently drilled discovery wells on adjacent fields. The expectation was that a cross-discipline team of engineers and geoscientists could plan one well - without recourse to expensive updip / downdip geological sidetracks - to replace the two traditional and sequential appraisal and development well types.

This paper describes the Platina-2 well design and planning process followed to appraise all options and select the best wellplan to meet all the objectives. Given the present high cost and the forecast cost increase of deepwater well operations, the Platina-2 well planning process provides a useful example for future deepwater drilling operations where the two traditional appraisal/development well types can be rolled together into one combined well and save a considerable amount of field development CAPEX.

The Platina-2 well design and its Statement of Requirements (SoR) are now complete and frozen; pending further detailed definition and eventual spud when a slot becomes available in the rig schedule.

Platina Overview

The Platina field is located in the Western region of Block 18 approximately 200 km offshore, Northwest of Luanda the Angolan capital (see figure 1). The structure is a North-South trending, North plunging, antiform formed by salt emplacement. Subsequent graben collapse due to Pliocene-Miocene salt withdrawal has divided Platina into two geographical regions; Platina Main and Platina West (see figure 2). Platina-1 was the first well to be drilled in Block 18 by BP in 1999 and encountered 3 reservoir intervals (M55, O71 and O72) in what is now termed the Platina Main area.

The Platina West field is forecast to cover three unconsolidated sandstone horizons which the Platina-2 well trajectory will be the first to penetrate.
Jurassic Fault Framework and Structural Style in Bahra and Its Impact on Fracture Development
Authors: Banik Nikhil , Singh Sunil Kumar , Al-Dohiem Aref Abdulsalam Abdullah , Al-Ajmi Neema Hussain
Published: February 2016

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

Jurassic discoveries in Kuwait during recent years have met with potential successes and are among the landmark achievements in its exploration history. In this list, the success in Bahrah area of North Kuwait attracts special significance for its light oil production from fracture dependent permeability/porosity from an otherwise low matrix porosity carbonate reservoir. Middle Marrat and Najmah Formation within the Jurassic are main recognized reservoirs with proven hydrocarbon in Kuwait. The well evidence in and around the area suggests that Middle Marrat Formation in Bahrah area is of mud prone facies in an outer mid ramp to outer ramp setting having low matrix porosity. Therefore, hydrocarbon potential and productivity of Jurassic reservoir dominantly depends upon open fracture net work connectivity. To evaluate this reservoir characteristics and favorable hydrocarbon traps, the structural style of Bahrah and their fault framework were analyzed through detail mapping of the area. The study brought out N-S elongated faults which changed dominantly to NW-SE direction towards north. This change of fault orientation impacted a rotation effect over a considerable area which is expected to develop intense fracture zone. The large Bahrah prospect is also a combination of several independent structural and fault closures associated in a compressional stress system that paved the way for good fracture development. Seismic attributes such as spectral decomposition, edge slices, and frequency related trace attributes coupled with fracture interpretation from core and image logs of the wells have led to infer these fracture corridors. The studies through geomechanical modeling, curvature maps further consolidated the possible recognition of fracture corridors in the area. Use of ant tracking to define the sub seismic scale finer faults and lineaments are identified to track fracture corridors and appropriately placing the well locations with desired deviations to penetrate through more number of fractures.
Seismic Attribute Analysis - An Aid in Fracture Play Mapping
Authors: Narhari Srinivasa Rao , Banik Nikhil , Singh Sunil Kumar , Al-Adwani Talal Fahad
Published: February 2016

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

Najmah-Sarjelu formations corresponding to the Kimmeridgian-Bajocian stage are established source rocks in the Middle-East. Recent concerted and dedicated exploratory efforts in Kuwait have seen the successful up-grade of these formations in to a potential reservoir rock with the contribution from fracture associated porosity. This paper examines the role of various seismic attributes in the identification of fracture corridors of this play. The data presented here are from the Raudhatain field and North West Raudhatain field areas of North Kuwait. Based on 3-D seismic data a number of seismic attributes such as, Coherency, EDGE, Dip, Dip Azimuth and Spectral Decomposition have been generated in the zone of interest to understand the distribution of the fault network, which in turn has helped in the identification of fracture corridors. The application of these attributes has highlighted the presence of minor lineaments which have an impact on the fracture generation. Following methods were applied in generating the attributes:Window based application along the seismic reflection event,Volume based application in the zone of interest andVolume based application parallel to the very strong Tithonian Gotnia salt reflector.

Integration of these attribute data sets has resulted in the generation of a detailed fault and lineament map of the area. Some of the attribute data were further refined by means of fault tracking algorithms. Multi-volume visualization has helped in identifying areas with higher probability of encountering fracture networks. Exploratory locations were selected based on the integration of these data sets and in structurally favorable locations. Subsequent drilling results have been very encouraging by encountering fractures according to expectations. Application of multiple seismic attributes has evolved into one of the primary drivers of success for this play.
Utilization Of Innovative Technologies To Meet Increasing Oil Demand
Authors: Zorbalas Konstantin , Alomrani Majed Mohammed , Saeed Saeed
Published: February 2016

In an effort to improve well production performance targeting recent increases in oil demand, Saudi Aramco implemented several innovative technologies and practices in its offshore assets in the Arabian Gulf. The identified challenges which followed past practices were focused on enhancements to existing well completions, chemical treatments of damaged wells, implementation of Smart field technologies and early detection of casing leaks to enhance wellbore integrity and meet environmental standards.

This paper describes the methodologies of four technologies which were tested and implemented in three major offshore fields in Saudi Aramco. These technologies are the use of passive inflow screens combined with swellable packers in horizontal sidetracked wells to prevent premature water or gas encroachment, smart in-situ gas lift completion which utilizes the reservoir gas cap for artificial lift of oil wells, the chemical treatment of wells which endured formation damage and the utilization of a modified ultrasonic tool for early casing leak detection in aged wells equipped with up-hole packers.

All these technologies proved to be successful and their combined application added value to Saudi Aramco's operations. As a result, the production targets for 2006 were met and the positive results obtained from the implementation of these technologies will lead to the optimization and improvement of future operational practices.

Background

Saudi Aramco operates three major offshore fields in the North part of the Arabian Gulf and horizontal drilling in these three fields is dated back to more than a decade. The company has been prudent in evaluating the technology of drilling and completing horizontal wells as it was progressed with time and constantly improving the designs of horizontal completions to maximize reservoir recovery. As the number of horizontal wells increased in the fields, the reservoir sweep efficiency is improved with time and higher production rates were accomplished on a per well basis when compared to vertical producers.

The geology in one of the fields is rather complicated with the existence of stringer sand bodies which are usually separated from the main sand by an impermeable shale break (Figure 1). The stringer sands were deposited uncontrollably in the subsurface and pose enormous challenge in the well placement and deciding on the direction of the wells when it comes to horizontal drilling.

The three major offshore fields were discovered in the mid-fifties and have been on production since then. Their petrophysical properties are characterized by clean coarse sands with very good permeability in the range of 3–5 Darcies (D). The recovery mechanism is by natural water drive and in some areas it is complemented by a gas cap drive. The sandstone reservoirs have pressure support by a strong water aquifer, which underlains the sand bodies.
Derivation of Relative Permeability and Fractional Flow Behaviour From the Inversion of Saturation Logs in Horizontal Wells With Application to Water Shut-Off and Predicting Volumetric Sweep Efficiency
Authors: Harris Jeremy
Published: February 2016

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

DESCRIPTION

An inversion method is presented that uses saturation log profiles recorded in horizontal wells to derive relative permeability and fractional flow properties for a waterflooded carbonate reservoir. Observed water saturation profiles decreasing horizontally away from hydraulically conductive faults suggest a line-drive type encroachment of water into the fault-bound matrix blocks. The waterfronts have produced saturation profiles analogous to that predicted by Buckley-Leverett displacement theory, including the characteristic shock front. These profiles record parameters such as irreducible water saturation, the shock-front saturation, average saturation behind the front, and the residual oil saturation. These parameters are used to define boundary conditions on a fractional flow plot using Welges method. A fractional flow curve which meets the boundary conditions is then derived by changing the shape of the controlling relative permeability curves. The observed saturation profiles also show a correlation with porosity, allowing a suite of scanning curves to be derived for each porosity class. The reliability of the method is demonstrated by plotting the average pulsed-neutron-capture log saturations at the perforations against the producing watercut at the time of logging on the fractional flow graph.

APPLICATION

The fractional flow curves are used to discriminate between wells that produce at the correct watercut from wells that could benefit from water shut-off. The curves are also utilised for forecasting waterflood performance.

RESULTS

Identification of additional perforation and water shut-off activities amounting to significant oil gains over the past three years from very mature well stock. Provided new insight into the oil displacement process inferring higher mobility to water than previously suggested from core-plug data. Improved modelling of well & reservoir performance.

SIGNIFICANCE

First time that nonsynthetic saturation-front profiles are presented in the literature and used to derive dynamic properties.