The Arquimia field is located in the Tertiary Veracruz Basin in southeast Mexico. The reservoir is characterized by shale, sandstone and conglomerates in different sedimentary systems with ages from Paleocene to Recent. Discovered in 2004, the Arquimia field is part of the Veracruz Asset, which originally focused on oil production. In 1999, Pemex re-assessed and revised its Veracruz Asset strategy and since 2000 has focused on increased activity in the Tertiary area of the basin.

By applying advanced exploration and development technologies, Pemex grew Veracruz Basin dry gas production tenfold over an 8-year period, from 45 MMcf/d in 1997 to 450 MMcf/d in 2005. Pemex then drilled a series of new wells with the objective of sustaining the continuous growth, with expectations of 760 MMcf/d by the end of 2006 and a goal of 1,000 MMcf/d by early 2007. The operator knew that achieving its objectives would require improving production at reduced cost, including using new technology. Horizontal wells with expandable screens were selected because of the area’s unique challenges, which include environmental issues (minimization of deforestation), water coning and improving gas deliverability.

Arquimia field analysis
Pemex conducted extensive analyses at Arquimia to determine optimum results versus cost and risk. In an investigation radius of 229.7 ft (70 m) of a reservoir width of 1,968.5 ft (600 m), a 72-hour pressure build-up test and a radial composite model for flow characteristics revealed reservoir permeability of 26 mD and skin near 2. Initial reservoir pressure was 3,300 psi (227.5 bar) at 150ÞF (65.5ÞC). Analyses included basic petrophysics, scanning electron microscope, wellbore stability calculations, triaxial testing and grain size distribution.

The original plan called for six vertical wells. The first, exploratory well (Arquimia 1), in

Figure 1. Express Screen installation assembly. (Image courtesy of Baker Oil Tools)
Veracruz Basin’s Upper Miocene formation of high-permeability and -porosity sandstone, was vertically drilled at 7,217.9 ft (2,200 m) and completed with cemented and perforated 3 1/2-in. tubing. Based on determination of a 5.6-mile (9-km) long reservoir extension and, in an attempt to assuage environmental impact in this sensitive area, all-horizontal and a combination of vertical wells were considered for the remaining wells. Core samples revealed that horizontal and vertical permeabilities were similar. The maximum drawdown for Arquimia 1 was 5.93 MMcf/d at 90 psi (6.2 bar); it was estimated that a horizontal well with 5.0-in. tubing at the same drawdown would produce 17 MMcf/d, nearly three times more than the vertical well.

A numerical simulation model of various combinations of vertical and horizontal wells, at constant rate based on production test and nodal analysis, indicated that a base-case well producing 36 MMcf/d would have a production platform of 4 years, followed by two years of declining production, with maximum cumulative production achieved at 6 years. Alternatively, an 80 MMcf/d base case would have a 1.5-year platform and decline thereafter, but would reach maximum cumulative production in only 2 years. Analyzing age to maximum production and life of well indicated that the longer the perforated length, the better the production would be. Water production was also analyzed, and the risk was determined to be similar, regardless of inclination. Based on net present value following analysis, Pemex determined that two verticals and three horizontals would produce the best effect and approached the remainder of the project with the goal of designing each successive well to be more efficient in terms of pressure drop throughout the reservoir-completion-tubulars system.

Drilling
The second vertical well was drilled and completed using 31¼2-in. cemented and coiled-tubing-perforated tubing. The first horizontal well was drilled with a 1,148.3-ft (350-m) horizontal section. The second horizontal well was similar but used a combination of 31¼2-in. and 5-in. cemented tubing in the horizontal section. Perforations were performed using coiled tubing in 20 intervals, and this well produced 31 MMscf/d.

The third horizontal well, Arquimia 41, was designed with expandable screen and larger tubing to reduce friction losses. Using a 6-in. drill bit, 5,019.7 ft (1,530 m) of displacement and 1,148.3 ft (350 m) of horizontal section at 87° inclination, the well was to be completed with 43¼4-in. EXPress expandable screen and 5-in. tubing.

Challenges for expandable screens
Improving gas deliverability and minimizing the effects of water coning were the two main drivers for investigating the use of expandable screens. The fifth well from the same location, which was also the third horizontal well, proved to be the most prolific gas producer in the entire field.

Based on the previous work to improve gas production, the nodal analysis indicated the need to increase flow area, which significantly reduced the pressure drops through the entire lower and upper completion. Yet Pemex also needed to maintain its current drilling and casing program, which has dramatically reduced operational time. The team believed the EXPress system could deliver the required improvement.

Expandable screen installation
The expandable screens were positioned across the adjacent sand face while using FORMpac openhole packers to isolate the shale stringers between and shutoff future water production should the need arise. A FORMlock Z liner hanger allowed for the system to be deployed and expanded using a variable 17 to 22% swage in a single trip.

The end results provided a post-expanded inside diamter ranging from 4.902 in. to 5.11 in., based on the variable swage range and any restrictions encountered during the expansion process. This provided the largest possible flow area for the 300-plus-m lateral section, enabling the friction losses of the high-rate gas well to be minimized based on current construction.

Results
The Arquimia 41 well was drilled and completed in 47 days. During production tests, no sand was produced, and the well was cleaning itself during initial stages and exhibited fast stabilization for the 1-in. and 113¼16-in. chokes.

EXPress screens provide 30% inflow area. Thus, installing the expandable screen system improved the inflow area five-fold over previously used perforating techniques and resulted in production of 87 MMcf/d through 5-in. tubing. With the upper completion designed for 5-in. tubing, the entire system pressure drop has now been reduced to the lowest level attainable within the current wellbore architecture. Gas rates increased dramatically, and water coning was minimized due to the optimization of inflow and flow area that the expandable screens provided. Despite a 10% increase in capital expenditure over the initial six-vertical-well plan, the resulting internal rate of return increased from 54% to 291% and generated US $1 million additional NPV.

Setting a record for the highest gas production from a single dry gas well in Mexico, the Arquimia 41 well provides over 20% of the total field production. This field will benefit from further application of expandable sand screens. The technology has also gained widespread acceptance across the northern gas-producing regions of Mexico in the Papan field, located in the Veracruz Basin, and the Reynosa field. The southern region is currently evaluating the possibility of using this same technology for future gas production development.

Applying Baker Oil Tools EXPress expandable screen technology to horizontal wells in the Arquimia gas field has enabled Pemex to achieve aggressive production objectives with reduced cost and risk, and helped bring on line the highest-producing single gas well in Mexico.