bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sajaa Underbalance Coiled Tubing Drilling "Putting It All Together"
Authors: Pruitt Randal , Leslie Charlie , Smith Bruce , Knight Jeff , Buchanan Richard 
Published: December 2007

Abstract

Introduction
Located in the Emirate of Sharjah, United Arab Emirates, the Sajaa onshore gas field is a Thamama limestone reservoir ranging from 11,000 to 13,000 feet true vertical depth (3350 to 3960 meters true vertical depth). The bottomhole temperature is in the 260 to 310 degrees Farenheight (126 to 154 degrees Celcius) with bottomhole pressures of 1100 to 1900 psi (75 to 129 atmospheres). This paper will discuss the process used in basis of design, selection of bidders, pre tender qualifications, underbalance modeling, pre qualification, assurance testing of equipment, initial rig up, two phase nipple milling, window milling and the drilling of the first six wells in the Sajaa Underbalanced Coiled Tubing Drilling project.

Background
In April of 2002 a Production Technical Limit (PTL) meeting reviewed the wells and reservoir and identified the prize of unlocking additional permeability and height to gain additional rate and reserves. The PTL also identified the work required for sub surface evaluation of the reservoir with the basic questions of how much gas is left and where is the gas located. Idea's were then put forward on various options of snub drilling, conventional underbalance drilling as in the 2000 campaign, and coiled tubing drilling. All the options had one thing in common and that was the use of multi lateral wellbores to connect gas zones not fully connected with the vertical well mother bores. Coiled tubing drilling was evaluated as the best choice because of the need for real time directional steering where mud pulse is not possible due to the two phase fluids being pumped down the coil.
In June of 2002 a Peer Assist was held in Sharjah with invited BP quests and distinquished underbalance/CTD/snubbing experts from Alaska, the North Sea, BP Houston's non conventional wells team, Service Company expertise from BP's experts in Colombia and underbalance consulting firms. The result of the three day meeting was a Risk Assessment with the Underbalance Coiled Tubing Drilling. Key areas of risk were:
Monte Carlo Simulation of Vertical Separators Handling a Network of Intermittent Gas Lift Wells
Authors: Caicedo Sergio , Trujillo Militza , Florez Horacio 
Published: December 2007

Abstract
To the present, most of the research concerning separation process has had a deterministic approach because it is oriented to steady state flow regimes. However, this assumption is far away when many artificial Intermittent Gas Lifted (IGL) wells are connected to the same separator. IGL has a FLOW/NO FLOW periodic condition associated with a long accumulation stage and a short production stage lasting about 20 minutes and 1 minute respectively. A stochastic algorithm was developed to simulate the separation process and the periodicity proper of each IGL well along with the unpredictable delay or synchronization between those wells. The simulation couples the dynamic mass balance equations in the separator and the Monte Carlo method for predicting the gas and liquid rates associated with the superposition of the IGL wells. The input parameters for this simulation were the following: daily gas/oil production and cycle time of each well, oil properties, separator's pressure, and temperature as well as the control scheme. The simulator output matched with less than 10% with field data. The results obtained with the approach suggested in this work could be used as new criteria in design, simulation and evaluation of separation facilities under fluctuating conditions.
Screen and Near-Wellbore Cleaning and Stimulation Tools Evaluation: Recent Experience in Well Operation
Authors: Harthy Aziz , Abdulkadir Ramzi , Sipra Iqbal , Saeby Jan , Raiturkar Avadhut , Bailey Michael , Venditto Jim 
Published: December 2007

Abstract

Proposal
Numerous oil-producing wells in Southern Oman are completed with wire wrap screens (WWS), internal gravel packs (IGPs), and predrilled liners. These wells produce from mature clastic formations where fines migration and subsequent blockage of screens can result in impaired oil production. In the past, conventional treatment using coiled tubing and a jetting tool has been chosen to remove this damage. The gains resulting from these intervention activities were more often than not short-lived. This lack of longevity required frequent well intervention and oil deferment, often resulting in a loss of revenue.
Recently, a systematic approach was undertaken to evaluate the wellbore cleaning and stimulation tools that are currently available in the industry. This approach was implemented as a trial of three cleanout tools in oil-producing wells. This paper describes the results of using these tools for cleanout and stimulation of sand screens.
Excellent success was achieved with a pulse-jetting tool operating on the Principles of Coanda effect. This tool is further described in the following sections, and results of its use in a number of oil-producing wells are presented. The effect of the cleanout procedure is presented in terms of initial production and sustainment of production level.
Slick Water and Hybrid Fracs in the Bossier: Some Lessons Learnt
Authors: Sharma Mukul M. , Gadde Phani B. , Sullivan Richard , Sigal Richard , Fielder Robin , Copeland David , Griffin Larry , Weijers Leen 
Published: December 2007

Abstract
In order to better understand the process of fracturing tight gas sands, a comprehensive data set was gathered and analyzed for the Bossier formation in the Dowdy Ranch field. The dataset collected on the APC Anderson #2 well represents one of the most comprehensive datasets ever collected for a commercial gas well. The entire interval was cored, and a complete set of core analysis was performed across the sands. Stress profiles derived from dipole sonic logs across the pay zone and in the shales below were calibrated with stress tests. The frac jobs were micro-seismically monitored with downhole geophones and included breakdown and mini-frac stages. Post fracture data collection included pressure buildup testing, production logs with multiple passes, and tracer logs with multiple isotopes. Additional data was collected on five offset wells in the field. Results from these wells will be presented in a companion paper.
The bottomhole treating pressures were found to be higher than expected based on the measured stress profiles. However, the higher treating pressures encountered did not result in excessive fracture height growth. This may be partially attributed to unexpected faulting providing a conduit for fluid leak-off, resulting in low efficiency and narrow fractures. Propped or effective fracture lengths derived from pressure buildup analysis and history matching production data were significantly shorter than designed frac lengths (or those predicted from uncalibrated frac models). The net pressure plots showed some evidence of proppant bridging even at low proppant concentrations, again indicating only limited fracture widths were being achieved. The data collected and analyzed provide valuable insight into the performance of water and hybrid fracs in tight gas formations. Recommendations for the design of future fracture treatments are made based on the findings.
The Trouble Probability Plot: A New Measure of Drilling Maturity
Authors: Kravis S. , Irrgang R. , Scott P. , Lollback P. 
Published: December 2007

Abstract
Drilling performance is usually benchmarked by analyzing the time spent on well construction and the degree to which planned times and budgets are achieved. Learn curve analysis can provide indicators of relative improvement over a campaign, and position on the learning curve can provide a measure of process maturity. However, the variability of the data makes it difficult to obtain a good fit to the model and assess maturity. The principal cause of the discrepancy between planned and actual times is trouble. Trouble is accounted for in planning by a multiplicative contingency factor. This implies that trouble time is dependent on well or well section length. Based on a standardized analysis of drilling performance for a wide range of wells we find that this assumption is not valid and that trouble time is not significantly correlated with well or well section length. However, we do find that the probability of trouble is significantly correlated with length, and that a probability plot of trouble time for a group of wells or well sections provides a robust measure of drilling process maturity. We present results of applying this analysis to a variety of well types and propose some metrics for assessing drilling process maturity.
Subsea HIPPS: A Way to Develop High-Pressure Subsea Fields
Authors: Patni Sandeep , Davalath Janardhan 
Published: December 2007

Abstract
One of the challenges for the development of high-pressure oil and gas prospects in ultra-deepwater is the high CAPEX cost of subsea flowlines and risers. Installing a High Integrity Pressure Protection System (HIPPS) in the subsea system allows the flowline to be designed to just above well flowing pressure instead of well shut-in pressure. Based on flow simulations, pipeline design and economic analysis, this paper demonstrates that installing subsea HIPPS results in: Lower installed cost of flowlines and risersEarly payback with incrementally higher flow of oil and gasSecondary benefits including higher flowing wellhead and flowline temperatures.
Another important benefit from using subsea HIPPS is that the weight of the risers hanging off at the host facility can be reduced substantially. Otherwise, heavy-walled risers may restrict the tie-in of the deepwater prospect to host facilities.
With pressure decline over time, the thick walled flowlines become an overkill and will tend to restrict the well flow rate. With subsea HIPPS, the larger flow area in the subsea flowlines will allow the field to be abandoned at a lower reservoir pressure. This means that that the total recoverable reserves from the field can be increased. The major finding of this paper is that for high-pressure reservoirs in ultra-deepwater, installing HIPPS subsea accelerates cash flow and increases the project Net Present Value. These benefits will be illustrated based on the analysis of a deepwater field development design case.
Multiphase Well Surveillance with a Permanent Downhole Flowmeter
Authors: Webster M. , Richardson S. , Gabard-Cuoq C. , Fitzgerald J. B. , Stephenson K. E. 
Published: December 2007

Abstract
Flow rate and fluid type (phase) are two of the most fundamental parameters needed in characterizing well performance. Traditional methods of estimating these parameters, particularly for real-time detection and diagnosis of production anomalies, have been limited by sampling frequency and data quality. This paper presents field test results of a new type of downhole multiphase flowmeter, which confirm the value of permanent downhole metering. The meter contains only three sensors but is capable of direct multiphase flow rate and cut measurements without slip models, even in highly deviated, recirculating flow. The physics basis and flow loop tests are discussed.
Field Qualification of Four Multiphase Flowmeters on North Slope, Alaska
Authors: Hasebe Brant , Hall Andrew , Smith Bruce , Brady Jerry , Mehdizadeh Parviz 
Published: December 2007

Abstract
Multiphase metering technology continues to evolve, with significant implications for the oil and gas industry. Current technology is sufficiently capable for some oilfield applications and requires further development for others, particularly low-maintenance measurement of high GVF fluids. This paper discusses a field trial of four commercially available multiphase meters, including the test set-up, meter evaluation criteria, and general conclusions.
A Comparative Study of Mechanical Properties of Density-Reduced Cement Compositions
Authors: Ravi Kris , McMechan David E. , Reddy B. R. , Crook Ron 
Published: December 2007

Abstract
This paper discusses the tests conducted to determine the mechanical properties and the integrity of the cement sheath when subjected to cyclic loads. In addition, lower-density cement systems are discussed in this paper, along with how the density was lowered by incorporating conventional additives such as: Pozzolanic beads (cenosphere)Hollow glass beadsGas bubblesWater-binding additivesSilica fumeFly ash
Primary cementing compositions for oil-well applications are becoming increasingly complex and challenging because of the extremes encountered in well-operating conditions. The stresses exerted on the cement sheath during well operations could be severe enough to damage the cement sheath and negatively affect the safety and the economics of the well.
The results discussed in this paper should help operators design a cement sheath that can withstand the stresses from well operations and thus help improve the safety and economics of the wells.
Optimization of Well Placement with a History Matching Approach
Authors: Özdogan Umut , Roland N. Horne 
Published: December 2007

Abstract
Determining the optimum location of the wells is a critical and crucial decision to be made during a field development plan. The quality of the decision is strongly dependent upon the amount of the information available to the decision-maker at the time the decision is made. Knowing that the development phase of a reservoir is a dynamic period in which different categories of information are added to system from distinct sources, one should make the well placement decisions considering these time-dependent contributions of information. This study proposes an approach that addresses the value of time-dependent information to achieve better decisions in terms of reduced uncertainty and increased probable Net Present Value (NPV). A Hybrid Genetic Algorithm1 (HGA) was used as the optimization method to find the best locations of the wells. A utility framework, that enables the assessment of the uncertainty of the well-placement decisions, was used to find the optimum decisions for different risk attitudes. Through this new approach, production history data obtained from the wells, as they are drilled, are integrated into the well placement decisions. Unlike previous approaches, well placement optimization is coupled with recursive history matching steps. To test the results of the proposed approach, an example reservoir was investigated with multiple realizations, all of which match the history response of the reference. At each step of optimization, a reduction in the uncertainty of the multiple realizations was observed, as production history became available.
Dynamic Reservoir Well Interaction
Authors: Sturm W. L. , Belfroid S. P. C. , van Wolfswinkel O. , Peters M. C. A. M. , Verhelst F. J. P. C. M. G. 
Published: December 2007

Abstract
In order to develop smart well control systems for unstable oil wells, realistic modeling of the dynamics of the well is essential. Most dynamic well models use a semi-steady state inflow model to describe the inflow of oil and gas from the reservoir. On the other hand, reservoir models use steady state lift curves for modeling of the wells. When producing oil from thin oil rims, this description does not sufficiently describe the well behavior observed in practice. For this reason, a model was built that describes both the dynamic flow of oil and gas towards the well bore and the dynamic flow inside the well. The integrated model provides a realistic description of the well dynamics on a time scale of minutes, which is the time scale that is required for development of a control system. As a result, the integrated model allows the development of model based gas coning control or water coning control schemes, as well as model based interpretation of well data.
Hydrate Inhibition in Headers with No Production Flow
Authors: Herrmann B. , Bargas C. , Svedeman S. J. , Buckingham J. C. 
Published: December 2007

Abstract
When deep-water subsea production is shut in for long periods, measures are normally taken to prevent the formation of hydrate blockages in the flowline network. One common inhibition method is to inject methanol into the jumpers, manifold headers, and well bores. This paper presents the result of experiments that were conducted to investigate the distribution of inhibitor injected into a static (no production flow) header or bore that contains oil, water, and gas. The test results were used to help develop a more effective header design and also to shape operating guidelines for inhibiting after shut-in. A test facility was constructed to test various header configurations and production conditions. Tests were conducted to investigate the effect of varying the water cut, gas volume fraction, header inclination angle from horizontal, and the oil density. Experiments also examined the distribution of methanol injected into a vertical well bore.
Results are presented that show the dispersal of oil, water, and gas in the header after shut-in and after injecting inhibitor into the header. In all test cases, uninhibited water remained in the header after methanol injection and no protection was provided against hydrate formation. Either the methanol never came into contact with the water or the diffusion in the static system was so small that the methanol and the water remained segregated.
Test results also show that the maximum amount of inhibitor present in the header after methanol injection depends upon the oil density, header geometry, and the amount of gas trapped in the header. These results can be used to determine the maximum amount of inhibitor that needs to be pumped to inhibit a shut-in header section.
Given the apparent failure of methanol to disperse in such a way as to inhibit water, further tests were run to examine why this common practice of methanol inhibition is successful. These experiments gave some explanation for the success of this procedure and yielded insights to the timing of chemical injection.
Novel Perforating System Used in North Sea Results in Improved Perforation for Sand Management Strategy
Authors: Hillestad Eivind , Skillingstad Paal , Folse Kent , Hjorteland Oyvind , Hauge Janne 
Published: December 2007

Abstract
When performing hydraulic fracturing treatments, the completion community widely recognizes that if the perforations can be oriented to the maximum principle stress plane and the shot density can be maximized accordingly, the success of the fracture treatment will be much greater. These benefits result from the lower breakdown pressure and the minimal tortuosity effects experienced during the process when the above conditions are met. Also, if the perforations are oriented in the maximum principle stress plane for a naturally completed, cased, and perforated well, the resulting perforation tunnels will usually be more stable than other perforations that are placed away from this preferred stress plane.
In natural completion scenarios, oriented perforating becomes especially important if 1) the formation integrity is questioned, and 2) sustained production without the mobilization of sand that could impact production is challenged. Normally, when faced with this dilemma, operators have automatically defaulted to a conventional sand-control treatment to ensure that production is not interrupted and that costly well interventions to clean out wellbore sand accumulation will not be required. While traditional sand control methods; i.e., installation of screens, proppants, and completion fluids used in the completion, are capable of controlling unwanted sand production; significant productivity penalties are often experienced with their use.
Now, there is another viable sand-control option that can be considered by the industry. If the completion is a candidate for sand management, a gravity-force-oriented perforating strategy, which will eliminate traditional sand control treatments, can be planned. Since the system relies on gravity for proper orientation, the most important consideration for using this concept is that the wellbore under consideration must have a minimum deviation of 25 degrees to orient to maximum principle stress or the overburden gradient.
The new perforating system was used in a North-Sea field and resulted in a 37,600 BOPD sand-free production rate. The new gun system can be conveyed on wireline or coiled tubing and can also be used in conventional tubing-conveyed perforating (TCP) applications.
One-Trip Multizone Frac Packs in Bohai Bay - A Case Study in Efficient Operations
Authors: Vickery Harold , Baker Brad , Scott Randy , Black Dennis , Brown Pat 
Published: December 2007

Abstract
During the recent development of the Zhao Dong field in Bohai Bay, a One-Trip Multizone Sand Control System was combined with frac pack treatments for efficient completions in a series of stacked pay sands. These technologies were used to complete a total of 32 zones (28 frac packs and 4 circulating gravel packs) in eleven wells, in record time. This paper examines the factors that contributed to the success of these operations.
The One-Trip Multizone Sand Control system allowed pumping operations on each well to proceed with little or no interruption. While frac fluids were being prepared between pumping each zone, downhole sand-control equipment was repositioned and ready for the next frac pack. This allowed all of the frac packs on each well to be done in a few hours instead of days typical of this type of completion.
For the majority of the zones that were pumped, a mini-frac analysis was performed prior to redesigning and pumping the main frac job. The One-Trip Multizone tools allow live annulus data to be collected for a measure of the bottom hole treating pressure while the mini-frac is being pumped. However, once pumping has stopped on the mini-frac, pressure from the annulus does not allow actual monitoring of the pressure decline on the formation. The solution to this problem is discussed.
Due to rig space limitations, none of the frac equipment could be placed on the platform. It was placed on floating vessels in order to pump the frac packs. There was also shallow water depth around the platform. To help solve these logistical problems, two vessels were required. A fluids barge was refitted with the proper tankage and centrifugal pumps for moving drilling and completions fluids to the rig site. The other vessel was used as a platform for the pumping equipment, with all fluids mixed and stored on the fluids barge. This combination allowed pumping operations in preparation for each frac pack to proceed smoothly, without interfering with other rig operations.
Lessons learned about proper zone spacing, pre-job planning, and well preparations are also discussed.