bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Production from Flowing Wells: Minimizing Flow Restrictions Using Chemicals in Southwest Soldado Oil Field
Authors: Diaz Michael 
Published: June 2016

Abstract
Organic precipitation during the production of hydrocarbons has proven to be a production assurance problem experienced in the majority of oil and gas fields throughout the world. Paraffin and asphaltene deposition occurs in several areas of the production system including: the reservoir, wellbore components including the perforation face and production tubing, surface components such as chokes and on flowlines, and also in production equipment downstream. In an effort to maintain optimum production, removal of existing restrictions is essential, just as minimizing the deposition of same. There is no universally effective treatment for organic deposition. Proper identification of the deposit, design and implementation of the treatment is essential to the cost effective production of oil and gas wells experiencing the problem. The most common methods of removal include: mechanical means, chemicals of various types, heat techniques and micro-organisms. This paper analyzes the results of a chemical treatment exercise executed in the Southwest Soldado Oil Field, an offshore asset owned by the Petroleum Company of Trinidad and Tobago Limited (Petrotrin). A paraffin dispersant-asphaltene inhibitor was applied as a method of cost-effectively optimizing production, in a field within which organic precipitation is inescapable as a result of the crude's nature coupled with conditions necessary for deposition. Successful application of this treatment in eight (8) flowing wells and seven (7) flowline segments resulted in increased production levels within the field, despite the production constraints experienced within the field at the time. As a result of this success, apart from expansion of the exercise and treatment on an annual basis, continuous chemical treatment systems were introduced to the field, as a means of minimizing deposition on flowlines and in flowing and PCP wells.
An Integrated and Reliable Workflow to Determine Critical Rates for Gas and Water Coning in Oil and Gas Reservoirs - A Multi Well Approach, Case Study Pemex, Mexico
Authors: Espinola O. , Guzman J. D. , Mehranfar Reza , Pineda H. 
Published: June 2016

Abstract
Commonly when fields are operated, there are several challenges to face and make profitable the operations, from the reservoir perspective one of the key challenges is when we have undesirable fluids that can cause cost in the operations and make more complex the production. This is the case when we have water or gas production in an oil reservoir or water production of a gas reservoir. First of all the productivity on the well can be affected, the recovery factor, and all the impact that can cause in the operations, costs, etc. When we talk about water production there are several possible sources associated to this problem, in the literature (Fig.1) there are at least ten know possible sources can cause water production, one of these problems considered is the coning phenomenon (Fig. 2). Eventually, the water or gas breaks through into the well and water from the aquifer and/or gas from the gas cap is produced along with oil. The water or gas production increases progressively after breakthrough time and may reduce significantly the crude oil production. Understand all the parameters that affect or influence coning is very important and also to be able to select the proper methods to analyze and mitigate it. In this paper the water or gas coning is examined covering some analytical methods and numerical reservoir simulation workflow applied to different reservoirs of the Veracruz Basin to understand the behavior of the wells, estimate the critical rates, the breakthrough time and establish a proper plan to this wells to avoid or mitigate the water and gas production; to reach this a numerical simulation workflow is proposed, examples and comparison is included when the wells are above or below critical rates.
Slug Flow Regime and Mitigation Using Transient Simulation, a Complete Workflow
Authors: Villalobos A. , Espinola-Gonzalez O. , Scott-Duran D. W. , Corsi-Regalado C. 
Published: June 2016

Abstract
Severe slugging occurs in different parts of the total production system. Slug flow is a major, expensive headache for oil producers and it has a negative impact on the operation of onshore and offshore facilities. It causes reduction on separator efficiency and unnecessary shutdowns. The study presented in this paper covers the total process to analyze slug flow pattern in a network and possible ways of mitigation.
The oil and gas distribution networks are complex and each present distinct but sometimes overlapping flow assurance challenges that will change over time. In this paper developed a workflow that simulate slug flow. The novelty of this workflow is the ability to perform a slugging analysis with different scenarios that mitigate slug flow. The fluctuations frequently lead to a reduction of separator efficiency caused by excessive liquid levels and pressure surges in the first stage separator. This solution, can provide a relative low-cost method to mitigate slugging and can help the operator to anticipate further decisions based on forecast production, although each system needs to be examined in detail to understand the current operation and the future performance changing the production conditions.
Evaluation of Exploitation Strategies for Gas Reservoirs with Water Influx in the Miocene Formation of the Veracruz Basin Through Numerical Simulation to Optimize the Recovery Factor
Authors: Espinola-Gonzalez O. , Guzman-Arevalo J. D. , Ramirez-Cuacenetl J. R. , Rocha-Carrascal M. , Mehranfar R. 
Published: June 2016

Abstract
Commonly when a conventional gas reservoir is produced always the recovery factor expected is between 80-90%, but when the water appears always the plans are subjected to changes, different considerations and several questions raises regarding how the reservoir will be affected. The most common questions are if the recovery factor will be affected, if the current production strategy will change, if we need to consider critical rates per well, if the plateau will change, reserves, production facilities, etc. The presence of water influx can alter the way the gas is produced by the reservoir as the water invades the gas reservoir, the displacement is not 100% efficient (M.Kelkar, 2008). On the other hand it has long been realized that gas recovery from a water-drive gas reservoir may be poor because of high residual saturations under water drive. The Agarwal study (Agarwal, 1965) showed the quantitative potential importance of water influx; its results indicate that gas recovery may be very low in some cases: perhaps as low as 45 per cent of the initial gas in place. So the important fact is that in gas reservoirs with water influx can change drastically the recovery then the expectations, unfortunately, water influx has forced abandonment of a number of gas reservoirs at extraordinarily high pressures, hence the importance to understand the effect of water in the reservoir based on static and dynamic reservoir parameters, and highlight the importance of gas recovery under water drive appears to depend in an important way on: (1) the production rate and manner of production; (2) the residual gas saturation; (3) aquifer properties; and (4) the volumetric displacement efficiency of water invading the gas reservoir. In certain cases, it appears that gas recovery can be increased significantly by controlling the production rate and manner of production. For this reason, the potential importance of water influx in particular gas reservoirs should be investigated early to permit adequate planning to optimize the gas reserves.
The methodology presented on this paper appraises the evaluation of four different exploitation scheme, trying to understand and determine the best exploitation strategy using a reservoir simulation model applied to two different reservoirs of the Veracruz Basin with different static and dynamic properties, and quantify the benefits to use the proper one to maximize the recovery factor. A detailed description of each reservoir will be review and results will be compared to emphasis that there is no rules to create exploitation plans for gas reservoirs it will depend on several factors.
Case Study: Hibiscus Field 14 Years on - An Integrated Multidisciplinary Approach to Characterize Uncertainty on a Mature Gas Field
Authors: Zimmer Colin , Singh Sidharth , Burrowes Arden 
Published: June 2016

Abstract
The Hibiscus field situated off the North coast of Trinidad is a large, stratigraphically isolated and well-connected gas field which has 14 years of production history. Notwithstanding this extensive production history and overall recovery, a number of key subsurface uncertainties have been identified. The scope of this study was to better understand reservoir complexity and define subsurface risk and opportunity.
An integrated and iterative multidisciplinary approach to reservoir modelling was applied in an effort to meet these objectives. A modern suite of workflows such as Monte Carlo Petrophysical analysis, conditioning of models to seismic attributes, experimental design based uncertainty analysis and assisted history matching were used to generate new static and dynamic reservoir models. The key aspect of this workflow was 20+ major static to dynamic model iterations and a large number of deterministic simulations to rank and asses the validity of static concepts. The learnings were subsequently applied to create a robust reference case, static and dynamic uncertainties framed and a static probabilistic uncertainty workflow developed to QC the deterministic case. A full probabilistic assisted history matching exercise on the dynamic model enabled a refinement of the volumetric ranges and provided critical insight through analysis of posterior uncertainty distributions.
The iterative workflow allowed concepts to be validated dynamically and it was demonstrated that high quality history matches could be achieved even after the removal of almost all dynamic multipliers – a common issue in simulation models. Significant improvements to pore volume distribution, the use of geologically derived dynamic baffles, and permeability distributions were amongst the key learnings on the static side. The probabilistic dynamic modelling was characterized by a strong GIIP convergence with a reduction of history match error, resulting in a refined volumetric range and better characterization of uncertainty ranges through posterior analysis.
The application of modern integrated and iterative workflows to a mature field has better defined uncertainty ranges, understanding of reservoir behavior and overall resulted in a more robust suite of models. Key learnings identified were highlighted to support future reservoir model rebuilds. Ultimately this process has demonstrated the value of revisiting existing datasets in late life assets by generating higher confidence in remaining reserve estimates and business plan forecasts.
Transient Multi-Phase Wellbore Flow Simulation to Accurately Predict End of Well Life and Enhance Recovery
Authors: Solomon S. , Kaasa A. , Singh S. , Pacho D. , Manrakhan S. 
Published: June 2016

Abstract
The field is a Pliocene, shallow-marine, gas reservoir offshore North Trinidad with one producer well and is believed to be supported by a moderate aquifer. In February 2014, formation water production was observed and with near term shut-downs in plan, there was a natural risk of losing the well during a shut-down due to liquid loading. Field remaining reserves were also at risk due to its single well development nature. To optimally manage the well and mitigate these risks, a better understanding of liquid loading and a more accurate end of well life prediction were identified as requisites.
In our experience, reservoir simulation models are unable to accurately predict well life post water breakthrough as they typically use steady state vertical lift performance curves whereas loading, shut-in and start-up operations are inherently transient conditions. Steady state lift curves are derived using nodal analysis and flow regime specific correlations and in case of liquid loading, are valid only for specific liquid film and droplet conditions – which cannot be guaranteed in practice. Thus, a transient multi-phase well flow simulator was used to model with higher accuracy lift performance at higher water cuts and reservoir pressures. This enabled a more robust calculation of liquid hold ups, pressure drops and allowed better prediction of liquid loading. A tuned well model was developed by matching historical data points and a sensitivity study performed using a range of reservoir pressures, chokes, gas rates, water influx volumes and WGRs. Production conditions potentially initiating liquid loading were predicted and were used to identify any near term shut-in periods during which the well could load.
Transient modelling results indicated that the well could die during a shut-in when reservoir pressure dropped below 235 pressure units. Production trend curves were used to forecast these conditions accurately in the near future. A combination of these techniques estimated the end of well life to be any time after Dec 2014, and in reality in Feb 2015 post a shut-down, the well was unable to unload and flow. This closely validated the predictability and robustness of the analysis. By building a better understanding of the high risk periods, more informed well management decisions were made during potential shut-in or choke back periods. This resulted in an extension of the well life and an incremental recovery of c. 2 – 3%.
For gas wells producing water, this is suggested as a robust workflow to closely predict end of well life conditions and timing and hence, support better management of the reservoir and operating conditions during those periods.
Development of a Real-time Decision-Making Dashboard for Drilling Homogeneous Unconventional Shale Plays
Authors: Driver R. P. , Atwal H. S. , Knight S. J. 
Published: June 2016

Abstract
In the current market of drilling programs that emphasise cost effectiveness, making optimum decisions in a dynamic real-time setting is very important. We have observed a disproportional reliance on intuitive decision making in upstream oil & gas operations. In this paper, we propose a process that enables data driven decision making. We then implement this process for a specific situation.
In homogeneous unconventional shale drilling, the number of factors that effect drilling performance are greatly limited. Well drilling times are relatively shorter and so many more wells are drilled in a short period of time. This allows for an opportunity to learn quickly from past wells. We developed a decision-making dashboard that uses data from past wells and helps predict the outcome of a change before it is made. We used multiple linear regression (MLR) as the statistical tool to derive correlations between parameters and drill rate (ROP). Historically, MLR has been used as a tool to optimize the conventional rotary drilling process. However, these analyses are based on limited field data and can yield inaccurate results. The introduction of new drilling technologies such as polycrystalline diamond compact (PDC) bits, rotary steerable systems (RSS), and horizontal well placement have render past models obsolete when applied to modern unconventional homogenous shale wells.
Real-time data were collected from the lateral sections of eight horizontal Marcellus Shale wells drilled from a single pad located in Greene County, Pennsylvania. Twenty-seven variables were identified and evaluated. A MLR of these variables was calculated for each of the eight wells. Weighted averages of the resulting coefficients were then used to derive a predictive ROP model. A decision-making dashboard was created using the coefficients generated through MLR on field data specific to the rig, well-plan, and area being drilled.
In conclusion, a novel method of making data-driven decisions in real-time was developed. This dashboard is especially useful because it formulates a method of extracting actionable information from historical data. Care must be taken to ensure data used for analysis are of good quality and specifically related to real-time applications. These considerations include rig limitations, formation types, well profiles, mud properties. Updating the dashboard with more data as it is gathered enables continued learning from historical well-data in a systematic, data-driven method that has not existed in the past.
Advances in Subsea Separation and Processing Resulting in Discharge of Produced Water at the Seabed
Authors: Prescott N. , Sankar K. , Swenson J. 
Published: June 2016

Abstract
As hydrocarbon fields in production mature, the resultant increase in produced water poses a problem due to the ever-increasing costs associated with handling and separation. Current technology requires produced water to be brought back to a host platform or onshore from offshore reservoirs to address this issue of produced water separation and disposal. Significant interest within industry exists for Subsea Separation Technology, especially where current technology is challenged. The need for new or improved technologies is particularly salient when considering the topic of seabed discharge of produced water. Interest is further magnified in regions such as Trinidad and Tobago, where exploration activities in deepwater blocks have commenced and subsea processing could prove advantageous when compared to topsides.
This paper will discuss the need for development and testing of a subsea produced water treatment system for seabed discharge and the ongoing efforts involved in commercializing this technology. Various existing subsea separation systems will be presented, with reasons why each has failed to render a solution to the issue of disposal of the produced water to the sea. A discussion will be made to illustrate the new era of linear separators, spherical separators, and compact flotation devices that may bring about a technology breakthrough for allowing subsea separation and discharge of the environmentally clean produced water to be discharged at the seabed.
Oil-in-water sensors enabling continuous measurement of produced water discharged at the seabed will also be introduced to illustrate current technology developments. The sensors' design basis and criteria are compared to existing discharge limits in the U.S. Gulf of Mexico and Trinidad and Tobago to highlight the benefits of their use in these regions. In particular, four (4) sensor technologies subject to bench-scale testing in mid-2016 and their working principles are outlined.
Success Story: Short-Term Expenditure Secures Long-Term Revenue in Brownfields
Authors: Patterson Aaronica , Francis-LaCroix Kyethann , Joseph Terry Ann , Sobrien Teri-Ann , Sanchez Alex 
Published: June 2016

Abstract
This paper presents a cost analysis / comparative study of the return on investment realized from the downhole chemical treatment of the Coora CO365 well. The technologies available to permanently outfit older wells that are completed with sub-surface safety valves (SSSVs), with the ability to benefit from direct down-hole chemical remediation, are also detailed.
Producing from a field that was first developed in 1936 and located in southern Trinidad, Coora CO365 experienced paraffin deposition in the near-wellbore and along the well's production string early in its productive life. The operator followed long-term strategic workover plans, but paraffin deposition still continued. Further investigation highlighted that the implementation of an optimal chemical injection program would be critical to realize maximum financial benefit from production of this maturing reservoir.
The operator has been able to replace high-cost workovers with low-cost chemical treatment, significantly improving the economics and prolonging the productive life of this well. Through comparison with older wells (in this block), completed without direct downhole means of chemical remediation, this case will show that simple modifications, though incurring upfront capital cost, can result in long-term revenue generation and early payback, if combined with an appropriate chemical remediation package. The analysis will dispel the common misconception that the cost incurred in refitting older wells with downhole injection capabilities overshadows their revenue generation prospects.
In many cases, the natural decline of a field can be exacerbated by flow-assurance issues in wells and equipment. This paper highlights the potential to sustain production in brownfields that have been plagued with these issues via the use of downhole chemical injection.
The Impact of Reservoir Size on Gas Field Development Options
Authors: Alleyne N. A. , Stoute V. 
Published: June 2016

Abstract
The deep water province of Trinidad and Tobago is the next producing frontier for this country. The area is of interest to a number of major oil and gas companies which have expressed interest in seven of the exploration blocks in the deep water province. An extensive seismic survey was conducted over the area in 2014 and exploration wells are planned for 2016/17. These wells will have to prove up a minimum quantity of resources for the exploration venture to be commercially viable. This paper is an investigation of the minimum resource required to support the development of a gas field in the deep water province of Trinidad and Tobago.
In the absence of published data on the deep water province, analogue data is used to estimate a minimum resource size for commercial exploration by investigating a number of scenarios, which represent the discovery of a total gas- in- place volume of 2 and 3 TCF, with a variety of reservoir sizes and condensate to gas ratios (CGRs), which are typical of those in the existing gas fields of Trinidad and Tobago.
Each reservoir case in the estimated range is used to investigate its own applicable optimum development strategy for taking the gas to market as liquefied natural gas (LNG), compressed natural gas (CNG), gas to solid petrochemicals (GTS), gas to liquids (GTL) and gas to wire (GTW). The paper establishes the total size of the accumulation and the associated reservoir sizes which could lead to commercial exploration in each case.
As exploration moves from the continental shelf into deep water in Trinidad and Tobago, one of the components geologists and geophysicists have specified is required for success in the search for gas reserves is finding larger trapping mechanisms. This paper seeks to estimate some limiting bounds for the designation of a successful find.