As the world’s oil and gas reserves are sought out and depleted, the search turns to more difficult targets. Many of the reserves that are now actively being exploited lie in tight reservoirs. Reaching these reserves demands better completion design than has been used in the past. The completions continue to increase in cost, complexity, and risk. Early completions were natural. Little attention was paid to completion fluids, reservoir mineralogy, rock-fluid interactions, natural fracture systems, stimulation, and geological setting. The use of acid to clean up completions is one of the oldest completion enhancements. In the early 1960’s, the sand-oil squeeze successfully enhanced production from tight, water-sensitive formations. In the 1970’s the massive hydraulic fracture treatment unlocked gas reserves in tight reservoirs. In the 1980’s foams found applications in completions. By the 1990’s, horizontal wells greatly modified the reservoir’s exposure to the wellbore, and the completion had to cope with prevention and treatment of formation damage. During all of this time developments in tool technology increased the options and complexities of mechanical wellbore configurations.

With the cost of completions rising more quickly than any other segment of oil and gas development, questions arise as to the effectiveness of completion design and execution. Some operators dismiss many of the completion techniques as a fanciful sport of the wealthy. Others diligently try to glean additional information about the local reservoir and optimize every aspect of the completion to increase production rates, return on investments, and ultimate reserves. Just how important is the completion design? What do we get for the time and money we invest in completions? Should we continue to increase our efforts in this segment of the industry, or should we simplify completions and spend money in more profitable ventures? This study looks at the effect of completions from the perspective of forensics or even an autopsy in a very mature tight oil sandstone.

The Importance of Reservoir Description

How much oil should a well produce? Intuitively, the volume of oil a well is capable of producing should be related to:

1. How much oil is in the reservoir (the oil reserve density)
2. The quality of the connection between the reservoir and the wellbore (the completion)

To calculate how much oil is in the reservoir, we can use the time-honored volumetric equation shown in figure 1 were: Oil in Place is stock tank barrels, A is the drainage area in acres, hnet is the net thickness in feet Phi is the porosity, Sw is the water saturation, Boi is the initial oil formation volume factor. All of the terms in the above equation are readily available from logs, except for the oil formation volume factor and the area. The oil formation volume factor can be obtained from laboratory fluid studies or estimated from correlations. The area can simply be ignored, changing the calculation from a calculation of barrels of reserves to a calculation of barrels per acre. This number is referred to as an Oil Reserve Density, or ORD. The ORD can be easily calculated for each well that is studied. It is useful to provide insight into the areal distribution of oil reserves. It is also very important to understanding what a well should produce.

A Technique for Evaluating Completion Effectiveness

Intuitively, the ORD should have some relationship to how much oil a well would produce. If one had a field that has been produced to the economic limit, the recoverable reserves for each well would be known, and the relationship could be examined more closely. This was done for a Parkman field in the Powder River Basin. When the cumulative production data was plotted on a log scale versus the ORD, a striking linear relationship emerged from the data. Figure 2 is a plot of cumulative production versus oil reserve density shows that while the correlation is good, there are several points that fall significantly off of the curve. The completions for the wells were researched and added to the plot. They fell into three groups with natural completions, acidized completions, and completions with the then-new sand- oil-squeeze(SOS) technique.

It was obvious that the completion was related to the deviation of the well from the straight line curve-fit. The natural completions fell far below the straight line. The acidized completions fell nearly on the straight line. The sand-oil-squeeze completions fell above the straight line. There even seemed to be a relationship between the size of the sand-oil-squeeze and the distance above the straight line. It should be noted that two of the points did not have logs to calculate oil reserve density and display a zero value, but did have cumulative production. This relationship was developed only for the wells in a single field, and it is not known if it will prevail in other fields. However, one use for the plot is diagnosing the effectiveness of the completion relative to other wells in similar reservoir situations.

There are also economic benefits to be drawn from the plot. If the cost of a well is estimated, and a value of production derived from that cost to breakeven, the plot can be used to convert a cumulative production to a reservoir quality required to pay out the well with a given completion. Figure 3 shows the uneconomic area of the plot for a $500,000 well at $15 per barrel for oil prices. A plot of the economic Implications of completion design shows that a well must be drilled in an area of the reservoir containing 4,750 STB per acre to break even with an average completion. It also suggests that with a better-than-average completion an economic well could be drilled in significantly poorer reservoir quality. In fact, the large SOS treatments increased the cumulative production by almost one order of magnitude. The size of the stimulation has quite a significant effect on the well’s ultimate reserves potential. The effect of stimulation size on cumulative production, figure 4 illustrates the effect of stimulation size on cumulative production for a given reservoir quality. If the breakeven well were drilled and completed with an acid job, it has the potential to recover 30,000 STBO.

If the same well were stimulated with a 40,000 lb sand oil squeeze, it would have the potential to recover 100,000 STBO. This indicates that the economics of a better completion would be much more favorable. In addition, it can be seen that the better completions open up poorer reservoir quality to economic development. What can this plot be used for? In mature fields, it can be used for workover and stimulation candidate identification. Even the rough economics can be distilled from this plot very quickly. In less mature fields when the cumulative production is not mature enough to plot, established decline curves can be used to estimate the ultimate reserves and then plotted. In newly developed fields, more established data from offset production may be used to provide an analogous basis for new completions. When enough data is analyzed from various fields, more rigorous analytical relationships may be developed for new field completion design.

The Importance of Completion Design

As can be readily seen from examining the data plotted in this format figure 4, the completion design is the most important factor in the ultimate reserve capability of a well after the oil-inplace.

Since you are working on a log scale for cumulative production, small changes in completion efficiency mean large changes in cumulative production. In fact, the difference between a marginal well and a good well relies heavily on completion efficiency. However, the completion must be fitted to the individual reservoir. In higher permeability reservoirs, the difference is going to be less dramatic. In tighter reservoirs, it will be more dramatic. The presence of clays, natural fractures, and lenticular sand development will all affect this analysis. The plot implicitly assumes that these factors are constant across the wells being analyzed.

In this case, if the cost of a 40,000 lb hydraulic fracture treatment completion is $150,000, the completion is capable of returning incremental reserves of 70,000 STBO. This is worth approximately $1,000,000 at $15 per barrel. The completion is returning seven times the investment on a non-discounted basis. This is a relatively low risk investment, since you already drilled the well and know how much oil is in-place. The cost of these reserves is approximately $2 per barrel. It is not uncommon to spend three or four times that for established production, and twice that for high risk exploratory reserves.

Completion Techniques

There are as many different completion techniques in practice as there are producing fields. Innovative engineering continually comes up with a new twist with the potential for unlocking more oil and gas. It is not the intent of this paper to evaluate the effectiveness of these techniques. They are numerous and sometimes very site specific. It is important to note that theyrequire serious thought as to their application.

Stimulation is probably the most important facet of completion design. Acidizing is one of the oldest forms of stimulation, but still one of the most misused. Hydrochloric acid does little to stimulate sandstones. It is effective in cleaning up producers plagued with scale problems. But it has the potential for causing serious damage to formations with iron-rich minerals, wettability problems, and reservoir fluid incompatibility. It is an excellent treatment for limestones and dolomites, however.

One relatively new technique that has good potential is propellant-enhanced perforating. This technique utilizes a propellant sleeve over the perforating gun that is capable of generating extremely high pressures during the perforating process. These pressures create a spherical fracture zone of about 2 to 3 feet radius around the perforated area that provides pathways in the very critical near-wellbore area. The process is capable of damaging the wellbore if not designed properly. The geometry requires computer simulations to calculate the forces that the wellbore is capable of sustaining, the rate of dissipation possible through the newly created perforations, and the reaction of the mechanical rock properties to the process. If properly executed, this completion provides superior communication between the near-wellbore area and the wellbore. It may be used in lieu of an acid breakdown. It is an excellent pre-treatment for hydraulic fracturing, reducing near-wellbore tortuosity.

Hydraulic fracturing is usually the stimulation of choice for tight reservoirs. They are the most complex stimulation capable of the most dramatic results. They also require the most engineering to be successful. Hydraulic fracture treatment design requires consideration to optimize fracture length, conductivity, fluid system, proppant selection, proppant loading schedule, pump rate, fluid loss control, height growth, treatment pressure, wellbore configuration, clay sensitivity, breaker systems, and flow back. Much of this requires a good reservoir description and flow model. Quality control is also essential to obtaining an optimum job. Many times it is acceptable to merely obtain a successful job and not think what the potential of an optimized treatment would have been.

Horizontal wellbores are gaining importance as a completion technique. Since they expose more formation to the wellbore, they are capable of much higher production rates and more efficient reserves recoveries. However, with drilling and completion fluids exposed to the reservoir over more area and for a longer period of time, the potential for formation damage is significantly higher than with a vertical completion. This can be offset by the use of underbalanced pressure techniques and more expensive non-damaging drilling and completion fluids. The importance of borehole stability and rock mechanics to successful horizontal completions is also being realized. The completion design issues of horizontal wells must be considered before the well is even drilled.