Offshore Mexico Research Articles

E&P Notes (December 2022)

E&P Notes (December 2022)

Collaboration Allows Introduction of Automated Advisory System in Offshore Well

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31443, “Operator and Service Provider Collaborate To Successfully Introduce an Automated Advisory System in a Wildcat Exploration Well Offshore Mexico,” by Peter Batruny, SPE, M. Razali Paimin, and M. Arriffuddin Allauddin, Petronas, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. _ The authors of the complete paper describe a collaboration between an operator and a service company formed during a project’s well-planning phase to evaluate the feasibility of automation for a holistic drilling-advisory platform that facilitates real-time decision making based on downhole and surface data. The collaboration resulted in a successful deployment of an automation platform as a solution to manage and mitigate risks and optimize drilling operations in exploration wells. Introduction The probability of nonproductive time (NPT) and invisible lost time (ILT) occurring in exploration wells is higher because of a lack of experience in the area concerned. The operator estimates that NPT caused by hole problems accounts for 22% of total NPT (Fig. 1). The authors’ work aims to apply a novel, automated drilling-operation monitoring technique on a wildcat exploration well in the Gulf of Mexico through the collaboration of operator and service provider. A collaborative framework and technology integration is applied to minimize the effect of uncertainty on NPT and ILT. Description and Application of Equipment and Processes The well is in the Salina Basin, approximately 67 nautical miles north of shore, with an estimated water depth of 66 m below mean sea level. The maximum planned well total depth was approximately 4400 m true vertical depth subsea. The proposed well lies in a four-way anticline structure. Despite the abundance of wells around the location, most exploration activities performed in the area have been focused on the Middle and Lower Pliocene (shallower) interval, causing well correlation at the Miocene stratigraphic interval to be extremely limited. In addition, the disparate thicknesses of the Pliocene sediments in the area create significant challenges in terms of geological correlation. Five offset wells were used as stratigraphy correlation, with distances ranging from 8 to 31 km. Downhole losses and borehole instability were experienced in all offset wells, with well-control events experienced in three out of five offset wells.

E&P Notes (January 2022)

E&P Notes (January 2022)

Forward Modelling for Structural Stratigraphic Analysis, Offshore Sureste Basin, Mexico

The stratal architecture of deep-water minibasins is dominantly controlled by the interplay of two factors, structure growth and sediment supply. In this paper we explore the utility of a reduced-complexity, fast computational method (Onlapse-2D) to simulate stratal geometry, using a process of iteration to match the model output to available subsurface control (well logs and 3D seismic data). This approach was used to model the Miocene sediments in two intersecting lines of section in a complex mini-basin in the deep-water Campeche Basin, offshore Mexico. A good first-pass match between model output and geological observations was obtained, allowing us to identify and separate the effects of two distinct phases of compressional folding and a longer-lasting episode of salt withdrawal/diapirism, and to determine the timing of these events. This modelling provides an indication of the relative contribution of background sedimentation (pelagic and hemipelagic) vs. sediment-gravity-flow deposition (e.g. turbidites) within each layer of the model. The inferred timing of the compressional events derived from the model is consistent with other geological observations within the basin. The process of iteration towards a best-fit model leaves significant but local residual mismatches at several levels in the stratigraphy; these correspond to surfaces with anomalous negative (erosional) or positive (constructive depositional) palaeotopography. We label these mismatch surfaces “informative discrepancies” because the magnitude of the mismatch allows us to estimate the geometry and magnitude of the local seafloor topography. Reduced-complexity simulation is shown to be a useful and effective approach, which, when combined with an existing seismic interpretation, provides insight into the geometry and timing of controlling processes, indicates the nature of the sediments (background vs. sediment-gravity-flow) and aids in the identification of key erosional or constructional surfaces within the stratigraphy.

Application of the Stacked Refraction Convolution Section to 2D Ocean Bottom Seismometer Wide-angle Seismic Data Along the Tamayo Through Basin, Gulf of California

The stacked refraction convolution section can be used as an interpretation tool in wide-angle refraction seismic data generated by air gun shooting and recorded by Ocean Bottom Seismometers (OBS). The refraction convolution section is a full-wave extension of the Generalized Reciprocal Method (GRM), a method frequently used in shallow refraction seismic interpretation, but not applied to deep crustal-scale studies. The sum of the travel times of the waves refracted in the same interface and recorded in a pair of forward and reverse profiles, time-corrected by the reciprocal time, is an estimation close to the two-way travel times of the multichannel seismic reflection sections, but with seismic rays illuminating the interfaces upwards. The sum of seismic traces is obtained with the convolution section. Furthermore, several pairs of convolved forward-reverse refraction recordings of the same area can be stacked together to improve the signal to noise ratio. To show the applicability of the refraction convolution section in OBS deep data, we interpreted the basement structure of the Tamayo Through Basin in the southern Gulf of California, offshore Mexico. We compared the results with both, a multichannel seismic section recorded in the same profile, and the previous interpretations of the same wide-angle seismic data modeled with ray tracing and tomography methods. The basement imaged by the stacked refraction convolution section is similar in geometry to that obtained by seismic reflection processing. The stacked refraction convolution section identifies the full extent of the basement and confirms the location of a nearly constant thickness volcanic layer in the northwestern half of the basin. However, only a small area of volcanic deposits is found in the shallower parts of the southwestern margin. We also show that the convolution process can be used to estimate the occurrence of lateral variations of seismic velocities in the basement, as a further application of the GRM to deep refraction data.

Palaeogeographical reconstruction and provenance of Oxfordian aeolian sandstone reservoirs in Mexico offshore areas: comparison to the Norphlet aeolian system of the northern Gulf of Mexico

Abstract Palaeogeographical reconstruction of the Oxfordian-age (Jurassic) depositional systems in the southern Gulf of Mexico is supported by detailed sedimentological analyses, detrital zircon geothermochronology and plate tectonic restorations. This integrated approach departs from prior local studies by placing the Bacab Sandstone, a major reservoir in offshore Mexico, in a larger basin- to regional-scale context. Sedimentary characteristics derived from detailed core description show how remarkably similar the Bacab Sandstone is to coeval sandstones of the Norphlet Formation of the northern Gulf of Mexico. A comparison of lithofacies associations suggests similar depositional processes and palaeoclimate regimes, with aeolian dunes forming near base level with adequate wind, sediment supply and arid climatic conditions promoting development of dunes and adjacent sabhkas. Construction of prominent ergs (aeolian sand seas) with lateral transitions to updip fluvial–wadi systems is envisioned in Mexico, comparable to the Norphlet of the northern Gulf of Mexico. Reservoir quality over the southern Mexican offshore area is variable, as numerous well penetrations over several decades have demonstrated. However, in the core area of the Ek-Balam Field, the best reservoirs have surprisingly good porosity and permeability for their age (Jurassic) and present-day depth of burial (>4000 m). However, published information is not definitive on the factors mitigating subsurface reservoir quality destruction. It is possible that similar processes preserving or enhancing porosity under deep burial conditions for the Norphlet are likely to have operated in the Ek and Balam well locations. Available petrographical data on framework grains are similar for Oxfordian sandstones in both the northern and southern Gulf of Mexico. Detrital zircon U–Pb geochronology, however, indicates that different source terranes supplied clastics to the Oxfordian Bacab and Norphlet sandstones. Detrital zircon geothermochronology age spectra indicate that the Mayan (Yucatán) Block was the primary terrane for the Bacab Sandstone. This is separate and distinct from Norphlet source areas that vary from Appalachian (Laurentian) to Pan-African (Gondwanan and peri-Gondwanan) terranes. While it possible that the Bacab and Norphlet sandstones were continuous and connected across the Yucatán margin that lies between the two areas, detrital zircon provenance results do not show any indication of common source terranes. Dimensional considerations, such as the contrasting ratios of Bacab and Norphlet source areas to their respective documented areas of deposition, also support the notion of separated aeolian palaeoenvironments.

E&P Notes (June 2020)

E&P Notes (June 2020)

Coexisting seismic behavior of transform faults revealed by high-resolution bathymetry

AbstractTransform faults have anomalously low rates of seismicity, but it’s not clear whether this reflects persistent earthquake-generating fault patches surrounded by creep, or the presence of creep and earthquakes at different times along the same patch. We use new, autonomous underwater vehicle high-resolution seafloor mapping to image the morphology of and offsets along transform fault segments in the Gulf of California, offshore Mexico. Fault zone structure imaged in this study shows evidence for the initiation and cessation of activity along individual fault splays over geologic time. A series of six identically offset depositional fans evidence 21–23 m of slip along the main transform fault, which could not have been produced by a single earthquake given the length of the transform. Rather, the lack of smaller-magnitude offsets indicates synchronous deposition and an absence of multiple slope failure–inducing earthquakes, which is consistent with the idea that creep and/or small-magnitude events occur asynchronously with large earthquakes in the slip history of a given transform fault segment.

Miocene to Holocene Marine Tephrostratigraphy Offshore Northern Central America and Southern Mexico: Pulsed Activity of Known Volcanic Complexes

AbstractWe studied the tephra inventory of 14 deep sea drill sites of three Deep Sea Drilling Project and Ocean Drilling Program legs drilled offshore Guatemala and El Salvador (Legs 67, 84, and 138) and one leg offshore Mexico (Leg 66). Marine tephra layers reach back from the Miocene to the Holocene. We identified 223 primary ash beds and correlated these between the drill sites, with regions along the volcanic arcs, and to specific eruptions known from land. In total, 24 correlations were established between marine tephra layers and to well‐known Quaternary eruptions from El Salvador and Guatemala. Additional 25 tephra layers were correlated between marine sites. Another 108 single ash layers have been assigned to source areas on land resulting in a total of 157 single eruptive events. Tephra layer correlations to independently dated terrestrial deposits provide new time markers and help to improve or confirm age models of the respective drill sites. Applying the respective sedimentation rates derived from the age models, we calculated ages for all marine ash beds. Hence, we also obtained new age estimates for eight known but so far undated large terrestrial eruptions. Furthermore, this enables us to study the temporal evolution of explosive eruptions along the arc, and we discovered five pulses of increased activity: (1) a pulse during the Quaternary, (2) a Pliocene pulse between 6 and 3 Ma, (3) a Late Miocene pulse between 10 and 7 Ma, (4) a Middle Miocene pulse between 17 and 11 Ma, and (5) an Early Miocene pulse (ca. >21 Ma).

Comments: Offshore Makes a Comeback

Editor's column 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 head-lines that surging shale production has. World offshore output has remained about 27 million B/D over the past decade. US Gulf of Mexico production, which is rising, made up a quarter of US output in the early 2000s but captures only 16% of the total now with the rise in unconventionals. US Gulf of Mexico production in 2017 rose to 1.65 million B/D, the highest annual level on record, according to the US Energy Information Administration (EIA). It is expected to increase this year and in 2019, maintaining record highs. Output will creep to 1.7 million B/D in 2018 and then to 1.8 million B/D in 2018, according to the EIA. This is due mainly to projects that were sanctioned before the price downturn and went forward in 2016 and 2017. The EIA says that seven deepwater fields will start production this year and another three will start up the following year. Shell will begin production from three fields over the period—Gotcha, Rydberg, and Kaikias. Hess and LLOG both will start up two fields, and Stone Energy and Apache will bring one field each online. An offshore auction by the US government in March, the largest for drilling prospects off the US Gulf Coast in history, attracted only modest interest from operators, proving that they are still wary of market conditions. The bidding was for 77 million acres of deep- and shallow-water tracts. Interest offshore Mexico and Brazil remains high. Brazil’s offshore auction in late March brought winning bids from ExxonMobil, Wintershall, Chevron, Shell, BP, Statoil, and Qatar Petroleum. Several operators said their break-even price for offshore projects is now under $50/bbl, well below where prices were trading in mid-April. The success of Brazil’s auction was not only because of rising oil prices and better capital discipline among operators, but also changes in Brazil regulatory laws that made the projects more attractive. That followed a deepwater auction in Mexico earlier this year that saw aggressive winning bids from Shell, which snatched up nine blocks, as well as Petronas and Qatar Petroleum. But offshore production will not catch US onshore output, which continues to outpace expectations despite fears of infrastructure bottlenecks and people shortages. Total US production will reach 11 million B/D this year, a whole year earlier than projected in March, the EIA said in April. Output is averaging 10.2 million B/D so far this year. The EIA expects US production to reach 11.18 million B/D next year.

Constraining the Source of the Mw 8.1 Chiapas, Mexico Earthquake of 8 September 2017 Using Teleseismic and Tsunami Observations

The September 2017 Chiapas (Mexico) normal-faulting intraplate earthquake (Mw 8.1) occurred within the Tehuantepec seismic gap offshore Mexico. We constrained the finite-fault slip model of this great earthquake using teleseismic and tsunami observations. First, teleseismic body-wave inversions were conducted for both steep (NP-1) and low-angle (NP-2) nodal planes for rupture velocities (Vr) of 1.5–4.0 km/s. Teleseismic inversion guided us to NP-1 as the actual fault plane, but was not conclusive about the best Vr. Tsunami simulations also confirmed that NP-1 is favored over NP-2 and guided the Vr = 2.5 km/s as the best source model. Our model has a maximum and average slips of 13.1 and 3.7 m, respectively, over a 130 km × 80 km fault plane. Coulomb stress transfer analysis revealed that the probability for the occurrence of a future large thrust interplate earthquake at offshore of the Tehuantepec seismic gap had been increased following the 2017 Chiapas normal-faulting intraplate earthquake.

Drilling Evolves as Exploration Campaign Moves to Deeper Water Offshore Mexico

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 25030, “Drilling Evolution of the Ultradeepwater Drilling Campaign in Mexico, Perdido Fold Belt,” by Victor G. Vallejo, Aciel Olivares, and Octavio Saavedra, Pemex, and Juan R. Lopez and Manuel E. Torres, Schlumberger, prepared for the 2014 Offshore Technology Conference Asia, Kuala Lumpur, 25–28.March. The paper has not been peer reviewed. During the 10-year period between 2003 and 2013, Mexico drilled 30 deep- and ultradeepwater wells in water depths ranging from 512 to 2900m. During this exploration period, the learning curve has improved with each subsequent level of difficulty and increased well depth. In order to reach water depths greater than 1500 m, both the wellbore geometry and the real-time data-acquisition strategy have changed. Introduction Fig. 1 shows how wellbore geometry evolved to reach geological targets and how the various hole diameters changed to meet exploration objectives. As seen on the left of the figure, a conventional drilling and data-acquisition approach was applied: drilling a 12¼-in. pilot hole for data acquisition and thereafter enlarging the hole to 17½ or 14¾ in. to set the casing. This enabled real-time logging-while-drilling (LWD) data acquisition and provided a 12¾-in. maximum hole size for wireline data acquisition. However, as water depth increased (right side of Fig. 1), the hole-size requirements for the mechanical well design increased accordingly. In some cases, with shallow geological targets, the required hole size of 22 in. was needed for the casing. This required a strategy to drill an appropriate hole size for LWD and wireline evaluation with minimal dedicated drilling and hole-enlargement trips. The evaluation programs considered realtime data needed to make decisions during the drilling phase and support decisions for a more- comprehensive wireline evaluation program if the zones warranted more extensive evaluation. The comprehensive evaluation logging suites included wireline-logging tools with triaxial resistivity, elemental-capture spectro scopy, nuclear magnetic resonance, vertical seismic profiles, mechanical sidewall coring, and the complete suite of formation-testing services for pressure and fluid sampling. The ultimate goal of the program was to provide accurate volumetrics, physical rock samples, and fluid samples for the booking of hydrocarbon reserves.

Reliability functions for buried submarine pipelines in clay subjected to upheaval buckling

This paper presents the reliability analyses for studying and quantifying the variation of the reliability index (β) with the main parameters involved during the upheaval buckling of submarine buried pipes caused by high pressure and temperature conditions (HPHT). The analyses correspond to typical geotechnical and operational conditions of pipelines installed in the Bay of Campeche, offshore Mexico. The parameters that mainly control the vertical uplift capacity of pipe-soil system and considered as uncertain are: the undrained shear strength of soils (Su) and the soil cover height (H). Driving vertical loading depends mainly on the levels on temperature and pressure combined with vertical imperfections (δ), therefore those parameters were also considered as uncertain. Model errors for both capacity and driving vertical force were estimated and applied in the analyses.The limit state function was established by comparing the uplift pipe-soil capacity with the vertical driving loading. Parameter uncertainty was covered based on literature reviews, information of the proper conditions for pipelines operating in the Bay of Campeche and numerical analyses.A lower-bound capacity of the pipe-clayey soil system was included in the reliability analysis and is a novelty of this work. Lower-bound capacity is the smallest possible physical limit of the uplift pipe-soil capacity and its effect on the reliability is studied. Furthermore, finite element analyses were executed to evaluate the uplift capacity of the pipe-soil system and determine the analytical model error for estimating the capacity.The reliability indices (β) of the pipe-soil system under upheaval phenomena were evaluated by means of directional simulations. Consequently, the reliability functions β-δ and β-H/D (ratio cover height over pipe diameter) were quantified. It was found that the inclusion of the lower-bound capacity by means of a left-censored distribution possibly increases β in comparison to the estimations using conventional distributions, the maximum increments observed are in the range of 22–34%.

Depredating sperm whales in the Gulf of Alaska: local habitat use and long distance movements across putative population boundaries

Satellite tags were attached to 10 sperm whales Physeter macrocephalus (1 whale was tagged in 2 different years) to determine the movements of sperm whales involved in removal of sablefish from longline fishing gear in the Gulf of Alaska (GOA). Tags transmitted from 3 to 34 d (median = 22) in 2007 and 7 to 158 d (median = 45) in 2009. Seven whales stayed in the GOA; all were associating with fishing vessels along the slope. Two whales headed south in June shortly after being tagged; one reached the inner third of the Sea of Cortez; the other's last location was offshore Mexico at 14°N. A third whale stayed in the GOA until October and then headed south, reaching central Baja, Mexico, 158 d after tagging. The whales that travelled to lower latitudes fol- lowed no pattern in timing of departure, and at least 2 had different destinations. All whales passed through the California Current without stopping and did not travel to Hawaii; both are areas with known concentrations of sperm whales. Whales travelled faster when south of 56°N than when foraging in the GOA (median rate of median horizontal movement = 5.4 (range: 4.1 to 5.5) and 1.3 (range: 0.6 to 2.5) km h �1 , respectively). Tagged sperm whales primarily travelled over the slope, but one spent considerable time over the ocean basin. Information on the timing and movement patterns of sperm whales may provide a means for fishermen to avoid fishing at whale hot spots, potentially reducing interactions between whales and fishermen.

Case History: Lessons Learned From Retrieval of Coiled Tubing Stuck by Massive Hydrate Plug When Well Testing in an Ultradeepwater Gas Well in Mexico

Summary A well-testing operation was performed to confirm productivity potential in an ultradeepwater area where a 5,660-ft exploratory well had been drilled. This was a gas well drilled from a semisubmersible drilling rig. Because well testing from semisubmersible rigs is a critical and sensitive operation, all planning had been carefully reviewed by the operator to ensure a safe, environmentally friendly operation. The formation of hydrate plugs during ultradeepwater well testing is a critical concern because water can be trapped and form a solid crystalline structure around gas when there are low temperatures near the mudline. This hydrate formation is a common occurrence in deepwater drilling operations, particularly while using water-based mud. Thermodynamic inhibition may not be effective in these cases because several limitations in achieving the required injection rate exist. Oilwell testing operations in deep and ultradeep water have become common practice around the world, and vast experience with these types of operations has been acquired; experience with gas wells, however, has not been as comprehensive, and only a few gas wells have been tested under the conditions presented in this type of scenario. Because of the low number of gas wells tested in these deepwater conditions, best-practice information is limited. The intention of this paper is to present a case history and the lessons learned during a well-testing operation in which water production in the gas well was greater than anticipated during the cleanup period. A massive hydrate plug was formed while coiled tubing was being pulled out of hole, and the coiled tubing became stuck. The steps taken to free the coiled tubing will be discussed, and the discussion will include the following: Conditions that must be present to form hydratesHow the problem in this case was resolvedHow to help prevent hydrate formationBest practices for well testing in deepwater gas wells to maintain safety and economic viability This case history discusses a gas well being drilled with a semisubmersible drilling rig in ultradeep water, offshore Mexico.

Numerical simulation of CO2 injection into fractured gas condensate reservoirs

More than sixty percent of the world’s remaining oil reserves are hosted by intensely fractured porous rocks, such as the carbonate sequences of Iran, Iraq, Oman, or offshore Mexico (Bedoun, 2002). The high contrast of capillarity between the matrix and the fractures makes a significant difference in the recovery performance of fractured and non-fractured reservoirs (Lemonnier and Bourbiaux, 2010). Simulation of naturally fractured reservoirs is a challenging task from both a reservoir description and a numerical standpoint (Selley, 1998). This paper presents the recovery performance of CO2 injection into a local fractured and faulted gas condensate reservoir in Western Australia. Tempest 6.6 compositional simulation model was used to evaluate the performance of uncertain reservoir parameters, injection design variables, and economic recovery factors associated with CO2 injection. The model incorporates experimental IFT, relative permeability data and solubility data at various thermodynamic conditions for the same field. These measurements preceded the simulation work and are now published in various places. The model uses Todd-Longstaff mixing algorithm to control the displacement front expansion. This paper will present, with aid of simulation output graph and tornado charts, the results of natural depletion, miscible and immiscible CO2 injection, waterflooding, WAG, sensitivity of fracture porosity, permeability and fracture intensity. The results also demonstrate the effect of initial reservoir composition, well completion and injection flow rate. All simulation cases were carried out at various injection pressures. The results are discussed in terms of transport mechanisms and fluid dynamics. This project was sponsored by a consortium of companies.

Field Development and Productivity Improvement Offshore Mexico

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 121928, ’Field Development and Productivity Improvement in Offshore Mexico: An Engineering and Lab oratory Synergistic Approach to Carbonate Fracture Acidizing,’ by Antonio Inda and Octavio Steffani, Pemex, and Eduardo Soriano and Fernando Robles, Halliburton, originally prepared for the 2009 SPE European Formation Damage Conference, Scheveningen, The Netherlands, 27-29 May. The marine light-crude project offshore Mexico is a group of 12 oil fields 75 km off the coast of southern Mexico. The fields have been under development since 2003, are high-temperature carbonate formations producing gas and condensate with permeability that ranges from 1 to 6 md, and are naturally fractured. These fields were experiencing considerable drawdown, which slowed down the return on investment and, in one case, could have led potentially to well abandonment. Established practice dictates that carbonate formations in Mexico are treated best by matrix stimulation rather than fracture-stimulation techniques. The full-length paper demonstrates the effective implementation of a production-optimization design and execution methodology that has translated into productivity increase. Introduction The use of various fracturing methods for stimulation of wells has become a common procedure in the oil and gas industry. Fracture treatments are performed on wells with varying potential to help increase production and reduce the pressure drop on the formation face. Many hydrocarbon-bearing carbonate formations are routinely stimulated by fracture acidizing, and the use of fracture acidizing to enhance the production of carbonate formations continues to be an effective process. To achieve a successful fracture-acidizing treatment, three fundamental issues must be addressed: (1) reactivity control, (2) fluid-loss control, and (3) conductivity generation. Stimulation Challenges Most of the wells in Field A are producing in low-permeability formations ranging from 1 to 50 md. Bottomhole static temperatures (BHSTs) in these wells are often above 300°F. This high temperature enhances acid reactivity and limits penetration into the formation. Established practice dictates that carbonate formations in offshore Mexico are best treated by matrix stimulation rather than fracture-stimulation techniques. This has been established and practiced during the last 20 years of development of fields offshore Mexico on the basis of previous formations being high-permeability carbonates ranging from 100 to 5,000 md. Traditional acid-stimulation jobs in this area were mixtures of solvents/hydrochloric acid (HCl)/organic blends, designed to overcome sludge precipitation and high BHST as a way to distribute acid along the producing intervals. Often, viscosified acids are used as diverter systems with some regular success; however, high reservoir pressure in these fields limit the pumping rates most of the time. Recently, an acid-fracturing campaign started in these fields reported outstanding results and is described in the full-length paper.

Successful Combination of an Organically Crosslinked Polymer System and a Rigid-Setting Material for Conformance Control in Mexico

Summary The Cantarell field, a mature reservoir offshore Mexico, presents significant water-management problems because the hydrocarbon production comes from a naturally fractured carbonate reservoir. Controlling water production in the Cantarell field becomes more critical because of its limited water-handling facilities. This paper presents the field application of two systems widely used in the petroleum industry for water control: (1) an organically crosslinked polymer (OCP) system and (2) a rigid-setting-material (RSM) system. The OCP system is based on a copolymer of acrylamide and t-butyl acrylate (PAtBA) crosslinked with polyethyleneimine (PEI). To date, more than 100 jobs have been performed in Mexico with this system to address conformance problems such as water coning/cresting, high-permeability streaks, gravel-pack isolation, fracture shutoff, and casing-leak repair. This system can penetrate deep into the matrix of the rock or fractures to provide a more efficient water shutoff. The RSM system is a rigid "cement-like" setting material that has a right-angle set. Unlike cement, the RSM system is capable of rapidly developing highly compressive strength to avoid losing the treatment to the formation before setting and will not invade the formation. The RSM system is for near-wellbore applications. Several case histories are presented in this paper to show the application of these two water-shutoff systems together. The OCP system was used for deep matrix/fracture penetration, while the RSM system was used as a tail-in because of its fast-setting properties (to avoid overdisplacement of the OCP system) and its capability to stop gas migration. These advanced water-control technologies have extended the well life and profitability of the treated wells. In the past, many of these wells were abandoned because of the limited water-handling facilities.

A review and technical summary of the AAPG/Associación Mexicana de Geólogos Petroleros Hedberg Research Conference on heavy oil: Origin, prediction, and production in deep waters

A joint AAPG/Associacion Mexicana de Geologos Petroleros (AMGP) Hedberg Research Conference was held to examine issues associated with heavy oil in deep water. This article reports on the meeting highlights. Deep-water exploration has become increasingly important over the last three decades. For the deep-water environment to be economically viable, these accumulations need to be both volumetrically significant and capable of maintaining high production rates. Largely independent of the rise in crude oil price, there has been an increasing number of economically viable deep-water discoveries, where the resource base now exceeds 100 billion bbl oil equivalent. A significant percentage of this resource is heavy oil, with heavy oil dominating the resource base in such settings as offshore Mexico and Brazil. Economic success in both exploration and commercialization requires integration across disciplines as well as across the value chain, integrating the upstream, midstream, and downstream operations. Basin models were commonly used as the integration tool for exploration programs. The exploration risks associated with the deep-water environment tend to be higher, in part as a result of oil quality. Risk reduction can be partially accomplished through a better understanding of the factors that control oil quality, including source rock facies, thermal maturity, and the alteration and migration histories. Although several factors may impact crude quality, the consensus was that biodegradation was the dominant factor controlling quality in most deep-water regions, Mexico being an exception, where source rock character has an important function. Biodegradation is controlled by such factors as charge and thermal history and the geometry of the oil-water contact. Where source facies is a key factor in establishing the presence of heavy-oil migration, distances tend to be more limited. Mixing of oils also appears to be an important factor in determining oil quality, often improving or maintaining oil quality, with the introduction of light oils into biodegraded oil. The production of these heavy oils introduces several challenges above and beyond those associated with similar accumulations onshore and in shallow waters. Lessons learned from these settings can, however, be very useful when working in the deep-water setting. The value of continuous data collection and updating reservoir models was made clear in case studies from both Angola and Brazil, where phased development or reservoir model recycling permitted the more efficient use of capital. Also of importance is the need for long-term planning because of the long lives of heavy-oil accumulations.

A New Method for Acid Stimulation Without Increasing Water Production

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 103771, "A New Method for Acid Stimulation Without Increasing Water Production: Case Studies From Offshore Mexico," by G.H. Reza, Pemex, and E. Soriano, SPE, L. Eoff, SPE, and D. Dalrymple, SPE, Halliburton, prepared for the 2006 SPE International Oil Conference and Exhibition, Cancun, Mexico, 31 August-2 September. Successful acid stimulation requires a method to distribute the acid between multiple hydrocarbon zones. Because almost all producing wells contain sections of varying permeability, this can be a problem. Because acid is an aqueous fluid, it tends to enter the zones with the highest water saturation. These water zones also are often the highest-permeability zones, so acid stimulation often will result in large increases in water production. The full-length paper describes use of a new low-viscosity system that reduces formation permeability to water with little effect on hydrocarbon permeability and also diverts acid from high-permeability zones to lower-permeability zones. Introduction In matrix-acidizing treatments, the acid tends to enter the highest-permeability layers and bypass the most-damaged (lower-permeability) layers. Various placement techniques have been used in attempts to achieve uniform placement of acid across all layers. The most reliable method uses mechanical isolation devices (such as straddle packers) that allow injection into individual zones until the entire interval is treated. However, this technique often is not practical, cost-effective, or feasible. Without a packer, some type of diverting agent must be used. Typical diverting agents include ball sealers, degradable particulates, viscous fluids, and foams. Although these agents have been used successfully, all have potential disadvantages, and none address the problem of increased water production that often follows acid treatments. One method of controlling water production uses dilute polymer solutions to decrease the effective permeability to water more than to oil. These treatments are referred to as relative permeability modifiers (RPMs), disproportionate-permeability modifiers, or bullhead treatments. RPM systems are thought to perform by adsorption onto the pore walls of the formation flow paths. Previous papers have described the development of and laboratory studies of an RPM based on a hydrophobically modified, water-soluble polymer, referred to as an associative polymer (AP). This group of polymers was selected for study because their properties can be altered in ways that render them valuable for oilfield applications. Another paper has described a laboratory study of this polymer for use as an acid diverter. AP Properties The solution properties of both ionic and nonionic, water-soluble polymers are uniquely modified when hydrophobic groups are introduced into the polymer chains. The primary factor responsible for the property modification is the associative tendency between the hydrophobic groups when placed in an aqueous medium. Previous testing has shown a unique shear-thickening phenomenon for the AP used in the current work. However, the solutions used in diversion operations show very low viscosity (less than 2 cp) at surface conditions.