A new class of permanent clay stabilizers has been developed inorganic based on an aluminum/zirconium-based compound. The increased charge density of the molecule allows it to bind more strongly to swelling clays, while its relatively low molecular weight allows it to stabilize the clay permanently without causing formation damage by blocking the pore throats and reducing permeability.
The most commonly used clay stabilizers are organic and inorganic chloride salts including trimethylammonium chloride, potassium chloride, and choline chloride. These salts have been used for years, are effective in most wells, and are both cheap and abundant. However, their high water solubility and the relatively small size of the cation means that these products are highly mobile and thus are quickly washed away during flowback. Several chemical derivatives were made from a tri-functional amine by reacting it with organic and inorganic acids such HCl, acetic acid, and formic acid; as well as alkylating agents, including chloromethane, benzyl chloride, diethyl sulfate, and paraformaldehyde.
Certain cationic polymers have also proven useful as clay stabilizers. These much larger molecules are not as easily washed away due to steric hindrance and a much higher charge density per molecule. These products have proved useful as long-term clay stabilizers, but their high molecular weights can lead to formation damage by causing them to be filtered out on the rock face.
In this research, several laboratory tests were carried out on the new clay stabilizer. These tests included coreflood experiments conducted on Berea sandstone cores to assess the stabilizer at high temperatures and the influence of different acids on its performance. Coreflood effluent samples were analyzed using inductively coupled plasma optical emission spectrometry (ICP-OES) to measure the concentrations of aluminum and zirconium.
This new permanent clay stabilizer improved productivity from formations that have high clay content by minimizing clay swelling and thus preventing formation damage caused by clogged pore throats and subsequent loss of permeability. It worked well at temperatures up to 250°F and with 15 wt% HCl and regular mud acid (12 wt% HCl, 3 wt% HF).
A key component of the fourth industrial revolution is data integration. However, this comes with a major challenge: handling increased input feature dimensionality. Multivariate feature space increases model complexity, memory utilization, and computational intensity, thereby reducing model performance. A pragmatic approach to input feature space reduction is therefore required. This paper presents a comparative study of the performance of a nonlinear feature selection methodology based on fuzzy ranking (FR). The FR algorithm is extracted from a segment of Fuzzy Logic, an existing machine learning technique. The performance of this feature selection algorithm is tested and validated with respect to the prediction of cementation factor as a log from wireline measurements using machine learning techniques. Cementation factor is denoted by the exponent
Heavy and extra-heavy crude oil reservoirs hold physicochemical characteristics that can frequently turn their operation into a technical and economic challenge. Typically, heating techniques are used to decrease oil viscosity. Areas with steam injection are susceptible to developing formation damage mechanisms such as scale precipitation that gradually restricts the flow of fluid towards the wellbore and ultimately decreases overall well productivity and/or injectivity. Acidizing treatments to either remove obstructing scale or to further increase near wellbore permeability are handled with caution: heavy oil is very sensitive and interaction with such conventional acids include asphaltene precipitation, sludge and emulsions.
Suplacu de Barcau is a shallow, heavy oil reservoir (16°API average) located in the northwestern part of Romania. It has been successfully operated with aid of both in-situ combustion and steam injection since 1960. Scaling tendency of condensed water from steam and its incompatibility when mixed with formation water frequently ends in scale build-up in injector and producer wells respectively. Identifying a fluid able to clean-out the scale deposits while being fully compatible with sensitive heavy oil, involved extensive screening a compatibility testing protocols. A formulation based on the chelating agents N,N, Glutamic Acid Diacetic Acid (GLDA) and Diethylene Triamine Pentaacetic Acid (DTPA) were found not only to effectively dissolve the plugging materials, but remarkably it was also noticed that it reduced significantly the oil viscosity, which made this formulation the most appropriate treatment for field application.
A number of 10 producer wells treated with the GLDA and DTPA based fluids delivered promising results by increasing oil rates by 3- 6 times of increase, significant improving steam coverage and penetration, decreasing drawdown and skin and ultimately enhancing the mobility of asphaltic oil. This paper describes the stimulation approach followed from diagnosis, fluid screening and selection, treatment design, job execution and results. Furthermore, the outcome of this stimulation campaign has shattered the myth that this type of stimulation does not work in hard oil.
A transient flow model capable of modeling gas solubility will be used to perform a sensitivity analysis of kick behavior in a subsea backpressure MPD system when using oil based mud. The parameters of interest are choke pressures, pit volume, and return rates. At HPHT conditions, gas kicks can be entirely dissolved in oil based mud. However, when being circulated upwards, free gas will emerge at a certain depth. The required choke pressure to maintain a constant bottomhole pressure depends on the amount of gas released from the mud and where this occurs. Another parameter that impacts both choke pressure and return flow is the geometry, whether we have a wide riser for subsea MPD or are considering an MPD operation from a fixed installation with a narrower geometry. In this paper, the riser geometry will be varied. The paper will contribute in showing how transient models can assist in the planning of MPD operations. It will also provide insight into influx behavior and its impact on surface parameters with focus on oil based mud.
Styward, Boris (Pertamina Hulu Mahakam) | Wijaya, Ryan (Pertamina Hulu Mahakam) | Manalu, Dasa (Pertamina Hulu Mahakam) | Wahyudhi, Fransiskus (Pertamina Hulu Mahakam) | Setiawan, Thomas (Pertamina Hulu Mahakam) | Dading, Albert Malvin (Pertamina Hulu Mahakam) | Rizal, Muhdi (Pertamina Hulu Mahakam) | Widarena, Tri Maharika (Pertamina Hulu Mahakam) | Lukman, Geraldie (Pertamina Hulu Mahakam) | Primasari, Indah (Pertamina Hulu Mahakam) | Merati, Putu Astari (Schlumberger) | Hezmela, Rizka (Schlumberger) | Fuad, Muhammad (Schlumberger) | Nwafor, Chidi (Schlumberger) | Hai, Liu (Schlumberger) | Singh, Pratyush
Pertamina Hulu Energi operates numerous wells that produce gas from unconsolidated, tight sands in the Mahakam Delta. The company maintains a zero-sand production policy as its surface facilities are not designed to handle sand. If sand is produced, the wells are choked back, thus impairing the overall field production. To fix sand and fines in place, the primary sand control method used has been multizone single-trip gravel packing, sometimes in conjunction with sand consolidation or ceramic screen for noneconomic zones. However, the current state of the Tunu shallow portfolio renders sand consolidation infeasible, as more than 50% of the remaining reservoirs are either low-stakes (i.e. not economical) or are located in low-permeability zones. Against this backdrop, sand conglomeration is being considered as an alternative solution to produce the remaining reservoirs. A trial has been conducted to assess the feasibility of using sand conglomeration technology as an alternative to sand consolidation in the Mahakam Delta, the results of which will be reviewed in this paper.
Colbert, F. C. (Baker Hughes, a GE Company) | Garcia, F. M. (Baker Hughes, a GE Company) | Costa, A. (Baker Hughes, a GE Company) | Gachet, R. (Baker Hughes, a GE Company) | Mattos, H. (Baker Hughes, a GE Company) | Junior, A. (Baker Hughes, a GE Company)
The Campos basin is a sedimentary basin located in offshore Brazil, between the north coast of Rio de Janeiro State and the south coast of Espírito Santo State. Most of the reservoirs on the post-salt layers are high permeability sandstones (2,000 mD up to 6,000 mD), containing low API gravity oil. In addition to the high permeability, these sandstones are unconsolidated, which demands a sand control method to make oil and gas production feasible.
In the original field development, conventional gravel packs were used as a sand control method, but post job analysis indicated high skins after the treatment, even using the best completion and placement techniques. This study offers an insight of the best practices and lessons learned from the design and pumping of more than 130 packs over more than two decades in offshore Brazil (water depths from 33 up to ~1800m). The main aspects discussed include frac pack design considerations, typical procedures, fracturing equipment overview, pressure management strategies and the need for a high quality fluid system and proppant.
Frac pack completions were introduced in the end of the 90's and became a usual completion method for the Campos basin. Post job analysis indicates that this type of treatment provided better results than the convention gravel pack including lower skins after treatment. Due to the challenging reservoir characteristics, the strategy for frac pack design was to create a highly conductivity fracture, aiming to reduce the skin as much as possible, by using aggressive Tip Screen Out (TSO) designs.
The TSO provides a short but wide and very conductive fracture, which is essential for high permeability wells. This technique bypasses the near wellbore damage caused by the previous drilling and completion practices such as drilling fluids, perforating debris and completion fluids invasion. This method can improve the effectiveness of the production, enhancing the oil recovery.
Penna, Rodrigo (Petrobras) | Araújo, Sergio (Petrobras) | Sansonowski, Rui (Petrobras) | Oliveira, Leonardo (Petrobras) | Rosseto, João (Petrobras) | Geisslinger, Axel (Shell) | Matos, Marcilio (SISMO)
The recent discoveries made in the pre-Salt carbonates, southeast Brazil, are among the World’s most important ones in the past decade. This province, especially Santos Basin, comprises large accumulations of excellent quality and high commercial value oil.
The latest seismic processing technologies along with Elastic Inversion have been used for reservoir characterization and in particular identifying carbonates with high-permeability intervals to model flow behavior of the reservoirs. One challenge encountered, however is identifying the occurrence of igneous bodies within the reservoir interval and their correct characterization as input into the reservoir modelling, once they may act as flow barriers or even high-permeability corridors, if fracturing is high enough.
Presentation Date: Wednesday, October 17, 2018
Start Time: 1:50:00 PM
Location: 209A (Anaheim Convention Center)
Presentation Type: Oral
Brazil’s state-owned Petrobras and El Dorado, Arkansas-based Murphy Oil have agreed to combine most of their US Gulf of Mexico assets to form a joint venture (JV) that will average 75,000 BOE/D in production during the fourth quarter. Murphy Exploration & Production will serve as the JV’s operator with an 80% stake, while Petrobras America will hold 20%. The deal excludes exploration blocks from both companies, with the exception of Petrobras’ blocks that hold deep exploration rights. As part of the deal, Petrobras could receive more than $1 billion, including $900 million in cash and $150 million if price and production benchmarks are surpassed during 2019–2025. Murphy will also cover $50 million of Petrobras' costs at the Chevron-operated St. Malo Field if enhanced oil recovery projects are greenlit.
All eyes in the upstream continue to be on the growth in unconventional production, particularly in the US. But the offshore arena may be making a quiet comeback, at least in the near term. The US Gulf of Mexico, North Sea, Latin America, and other spots have seen renewed interest of late, as operators enforce capital discipline to make these expensive projects feasible given the current price climate. Many offshore megaprojects were cut or scaled back when oil prices began to drop sharply in 2014 and, while global offshore output has been steady, it has not grabbed the headlines that surging shale production has. World offshore output has remained about 27 million B/D over the past decade.
In this drilling context, an accurate estimation of the downhole pressure is mandatory to avoid drilling problems such as kicks, lost circulation, and wellbore instability. When considering kick prevention and control, understanding of the mixture behavior (drilling fluid and formation gas) is essential to improve the estimation of the downhole pressure, which would support efficient, safe, and economic drilling operations. The widespread application of synthetic-based drilling fluids in the Brazilian presalt polygon is justified by the technical performance offered by this kind of drilling fluid, such as reduced drilling time compared with water-based drilling fluids, increased lubricity in directional and horizontal wells, and shale-swelling inhibition. In addition, this is an environmentally friendly alternative to oil-based drilling fluids. However, those fluids are more sensitive to pressure and temperature variations than water-based drilling fluids. To obtain a better understanding of the behavior of one specific kind of synthetic-based drilling fluid, the olefin experimental research was conducted and the results and findings are presented in this technical article. The work involved pressure/volume/temperature (PVT) measurements for olefin/methane mixtures to investigate the effect of pressure, temperature, and mixture composition on thermodynamic properties such as density, formation volume factor (FVF), gas-solubility ratio, and saturation pressure. Those properties are important for knowledge of the mixture volumetric behavior at downhole conditions, especially when gas enters the wellbore. The experiments were conducted at isothermal conditions, and a gas-enrichment experimental procedure was applied.